1

Transition Roadmap for the Shunan Power Corporation Power Plant in Shunan City, Yamaguchi
Prefecture (an Overview)
In its Guidance on Metrics, Targets and Transition Plans (“the Guidance”), the Task Force on
Climate-related Financial Disclosures (TCFD) encourages organizations to disclose key informationfrom their transition plans, including the following.
•

Current greenhouse gas (GHG) emissions performance•

Impact of low-carbon transition on businesses, strategy, and financial planning•

Actions and activities to support transition, including GHG emission reduction targets andplanned changes to businesses and strategy•

Target year, scope of GHG emissions, scope of businesses•

Assumptions, uncertainties, and methodology

The Guidance also lists the following as elements to be considered in a transition plan.
•

Alignment with climate change actions and business strategies•

Alignment with quantitative indicators and targets (alignment with science-based
decarbonization pathways)•

Assumptions underlying effective governance processes•

Actionable, specific initiatives•

Credible planning•

Periodical review and updates•

Annual reporting to stakeholders

In line with the above, we have formulated a transition roadmap for the Shunan Power Corporation
power plant, consistent with the international goals adopted in the Paris Agreement, containing thefollowing items.
Item

References

1. Project Overview and Governance・ Materials on Shunan Power Corporation’s power plant project

2. Current status of GHG emissions andchallenges (materiality of environmental
aspects)

・ Ministry of Economy, Trade and Industry, “Review Report on the Draft
Environmental Impact Statement for the Tokuyama Factory East Plant No. 3
Power Generation Facility Project” (February 2009) (in Japanese only)
・ Ministry of the Environment, “Opinions of the Minister of the Environment on
the Draft Environmental Impact Statement for the Tokuyama Factory East Plant
No. 3 Power Generation Facility Project” (April 17, 2009)

3. Impact of low emissions transition in
the electricity sector on the power
generation business

・ IPCC Special Report “Global Warming of 1.5°C”
・ IEA, “Net Zero by 2050: a Roadmap for the Global Energy Sector”
・ Ministry of Economy, Trade and Industry, “Transition Roadmap for the Power
Sector” (February 2022) (in Japanese only)

4. Short-, medium-, and long-term GHG
emission reduction targets and indicators
consistent with the Paris Agreement

・ Transition Pathway Initiative (TPI) “Sectoral Decarbonisation Pathways”
・ IPCC WG III contribution to the Sixth Assessment Report, Technical Summary

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5. Business transformation roadmap forachieving zero emissions at East No 3.
power plant・ Ministry of Economy, Trade and Industry, “Transition Roadmap for the Power
Sector” (February 2022) (in Japanese only)・ Mitsubishi Heavy Industries, Engineering Communication Sheet (July 22, 2020)

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Transition Roadmap for the Shunan Power Corporation Power Plant in Shunan City, Yamaguchi
Prefecture (Details)
1. Project Overview and GovernanceThis project refers to the construction and operations of a new co-firing power plant that uses coaland woody biomass, with a generating-end output of 300,000 kW, at 7-46, 7-51, and 7-52 Harumi
Town, Shunan City, Yamaguchi Prefecture, Japan (“the power generation project”). The project site ison the premises of the East Plant of the Tokuyama Factory owned by Tokuyama Corporation (“TK”),
and the name of the power plant is Tokuyama Factory East Plant No. 3 Power Generation Facility(“East No. 3”). This power generation project is scheduled to start commercial operations in
September 2022.
East No. 3 was originally planned as a private power plant at TK’s Tokuyama Factory. Stable,
inexpensive electricity is indispensable for manufacturing polycrystalline silicon, one of the main
products of the factory, and the purpose of the project was to meet the need for an expansion in theprivate power plant to increase production at the site, which was under consideration at the time, as
well as to address the anticipated future need to replace the outdated private power plant. Plans forconstruction were prepared and an environmental assessment was conducted in 2009. Due to thesubsequent change in circumstances surrounding TK, however, the company began approaching its
main business partners and other parties in December 2014 with the intention of jointly operating abusiness with a third party. Eventually, Marubeni Corporation (“MC”) expressed interest andapproached Tokyo Century Corporation (“TC”) about a possible joint venture. In April 2015, MC and
TC presented TK with a joint proposal for the power generation project as a collaborative venture
among the three companies, and after repeated discussions, the three officially decided to enter into
the power generation project in September 2017. An agreement had also been reached in March2017 to adopt coal-biomass co-firing instead of coal-based mono-firing.
TCLA Limited Liability Company (“TCLA”), an asset-holding, special purpose company (SPC), andShunan Power Corporation (“SNP”), a power generation SPC, were established as part of the power
generation project. Under the plan, TCLA will construct the power plant, and once operations start,
SNP will operate it under an operating lease agreement, with SNP taking over operations related toan environmental assessment from TK. TCLA was established by TC, and SNP was established by TC
with a 60% equity share, TK with a 20% equity share, and Marubeni Clean Power Corporation (“MCP”)
with a 20% equity share. TCLA will obtain project financing for the power generation project byseeking loans from financial institutions. TCLA will be responsible for decision making as the client in
the construction work for East No. 3, which will be handled by Mitsubishi Heavy Industries, Ltd.
(“MHI”). In addition, SNP will conclude an operation and maintenance (O&M) contract for East No. 3
with TK.

4

TC, as the main sponsor of TCLA and SNP, has indicated its intention to decarbonize the power
generation project by increasing the biomass co-firing ratio and switching to zero-emission power
generation in the future. As a joint venture of the three companies (TC, TK, and MCP), the transition
roadmap for East No. 3 is premised on coordination among the three companies.
Project SchemePower Generation SPC

Offtaker (Coal)
Tokyo Century: 45%

Ma rubeni : 45%

Tokuya ma : 10%

Offtaker (Biomass)
Chugoku El ectri c PowerTra ns mi s s i on &Di s tri buti on

Fuel s uppl y agreement

Sponsors (Shareholding Ratio)
Inves tment

Powerpurcha s e
a greement

Sha rehol der l oa n
Sharehol derbonds

Asset-Holding SPC

Seni or l oa nMarubeni Cl ean Power: 20%

Tokuyama : 20%

SNP(l es s ee)

TCLA(l es s or)

Opera ti ng l ea s e a greement for a dva nced equi pment

Powerpurcha s e
a greement

SponsorInves tment
Sha rehol derl oa nTerm: 10 yea rs

Coa l s tora ge a greement

O&M a greement, etc.

LenderSumi tomo Mi ts ui
Trus t Ba nk a nd 8
other s eni or
l enders

Tokyo Century: 60%

Superfi ci es a greement

Coal and Biomass Suppliers

Coal Storage

O&M, etc.*

Landowner

Ma rubeni ,Idemi ts u,
Bus s a n Sumi s ho CE, etc.

Shunan Bul k
Termi nal

Tokuyama

Tokuya ma

Tokyo Century:
100%

EPC a greement
ＥＰＣ
Pa rt of the coa l s tock
Mi ts ubi s hi
Hea vy Indus tri es yard to be ordered*Uti l i ty s uppl y, as h di s pos a l

s epara tel y

2. Current Status of GHG Emissions and Challenges (Materiality of Environmental Aspects)
On April 17, 2009, the Ministry of the Environment submitted the opinions of the Minister of theEnvironment on the draft environmental impact statement for the power generation project to the
Minister of Economy, Trade and Industry, including a request for further reductions in carbon dioxide
and air pollutants emitted from operations of the facility. The Minister of the Environment opinions
called for reducing the carbon dioxide emissions intensity of the entire power generation facility by
selecting a type of coal with low carbon dioxide emissions intensity and by co-firing biomass andother fuels as much as possible to reduce greenhouse gas emissions from overall project activities.
The power generation project plans to use white pellet (WP) at a co-firing ratio of 20 cal% at thestart of operations, and the CO2 emissions intensity is estimated at 592 g-CO2/kWh*1, excluding CO2
emissions from WP from the calculation. Annual CO2 emissions are estimated to be 300,000 kW
output × 7,543 h/year (operating ratio) × 592 g-CO2/kWh (CO2 intensity)/1,000,000 ≈ 1,339,637 tCO2/year. The average CO2 emissions intensity of ultra-supercritical (USC) coal-fired power generationin Japan is estimated to be 820 g-CO2/kWh, but with the CO2 intensity of the entire power sector
estimated to be 470 g-CO2/kWh in fiscal 2019, further CO2 reductions will be required.
The environmental load of air pollutants must also be reduced by practicing stringent maintenanceand management of flue gas denitrification equipment, desulfurization equipment, and electrostatic*1: Mitsubishi Heavy Industries, Engineering Communication Sheet (July 22, 2020)5

precipitators, and by taking additional appropriate measures as necessary to reduce the emission
concentration of soot, nitrogen oxides, sulfur oxides, and other substances. Once operations start,
emissions of trace substances such as heavy metals contained in coal must be promptly measured toconfirm the validity of projections, and appropriate monitoring must also be conducted if theproperties of the fuel used by the plant differ significantly from those in initial plans. Anotherimportant consideration is to request that appropriate measures be taken to manage coal dust during
operations of the Shunan Bulk Terminal.
3. Impact of Low Emissions Transition in the Electricity Sector on the Power Generation Business
Global Trends:
Net-Zero Emissions Must be Achieved by 2050 to Limit Global Temperature Rise to 1.5°C
The Paris Agreement, adopted in 2015, set a common global goal of constraining the rise in global
temperatures at well below 2°C over pre-industrial levels and pursuing efforts to further limit the rise
to 1.5°C of pre-industrial levels. Subsequently, “Global Warming of 1.5°C,” a special report released
in 2018 by the Intergovernmental Panel on Climate Change (IPCC), indicated that to limit the increasein temperature by the end of the century to 1.5°C above pre-industrial levels, global CO2 emissions
must be reduced by 45% from 2010 levels by 2030, and to net-zero by 2050*2. At the 26th Conferenceof the Parties to the United Nations Framework Convention on Climate Change (COP26), held in 2021,
the international community adopted a decision document stating its commitment to further pursue
the goal of limiting the rise in global average temperature to 1.5°C, as laid out in the Paris Agreement.
This has given an additional boost to initiatives for achieving net-zero GHG emissions. The IPCC’slatest Sixth Assessment Report (Working Group III Report) noted that in order to limit thetemperature increase to 1.5°C, global CO2 emissions must be reduced by 50% from 2019 levels by
2030*3.
A broad range of international organizations, including the IPCC, have noted the need to expand
and urgently decarbonize the power sector, which is the largest source of CO2 emissions. According
to the net-zero scenario of the International Energy Agency (IEA), the power generation sector indeveloped countries will be required to achieve net-zero GHG emissions by 2035, while net-zero will
be required globally by 2040. The IEA has pointed out that inefficient coal-fired power plants mustbe phased out by 2030, and those without CO2 capture and storage (CCS) equipment must be reducedby 70%*3. It also points out that the emissions intensity of the electricity sector needs to be rapidly
reduced from the 2019 global average of 0.468 t-CO2/MWh (468 g-CO2/kWh) to 0.138 t-CO2/MWh(138 g-CO2/kWh) by 2030*4. In the IPCC’s Sixth Assessment Report (Working Group III Report), thescenario for limiting the temperature increase to 1.5°C clearly states that the CO2 emissions intensityof the electricity sector needs to be reduced by 75% by 2030 compared to levels in 2019 (equivalent
to about 117 g-CO2/kWh)*5.

6*2: IPCC Special Report Global Warming of 1.5 ºC*3: IEA Net Zero by 2050: https://www.iea.org/reports/net-zero-by-2050*4: Transition Pathways Initiative: Carbon Performance Assessment of Electricity Utilities: Note on

Methodology, November 2021
https://transitionpathwayinitiative.org/publications/94.pdf?type=Publication*5: IPCC WG III contribution to the Sixth Assessment Report, Technical Summary, p34

Domestic Trends:
Transition Roadmap for the Power Generation Sector for Achieving Carbon Neutrality by 2050x
In October 2020, the Japanese government declared its goal of reducing overall GHG emissions to
net zero and thereby achieving carbon neutrality by 2050. This was followed by an announcement inApril 2021, in which the Japanese government stated its GHG emission reduction target of 46% by
fiscal 2030 compared to fiscal 2013 levels, while continuing strenuous efforts in its challenge to meet
the ambitious goal of reducing emissions by 50%. These reduction targets have been submitted to
the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC) as Japan’s
Nationally Determined Contribution (NDC) under the Paris Agreement.
Given Japan’s medium- to long-term targets for decarbonization, the reduction of CO2 emissions
from the energy conversion sector*6, which accounts for about 40% of emissions in Japan, is urgent.
In October 2021, the Cabinet of Japan approved a revised Plan for Global Warming Countermeasures
based on the Law Concerning the Promotion of the Measures to Cope with Global Warming, which
set the reduction rate of GHG emissions from the energy conversion sector at 47%, compared to fiscal
2013, in order to achieve the 46% reduction target by 2030. In addition, the Sixth Strategic Energy
Plan, approved by the Cabinet of Japan in October 2021, laid out a future path for energy policy basedon a long-term view toward achieving carbon neutrality by 2050 and policy responses for 2030 basedon the outlook. The plan also revised the energy supply and demand outlook for 2030 and calls for
maximizing the introduction of renewable energy, phasing out inefficient coal-fired thermal power
generation, as well as reducing the ratio of thermal power generation as much as possible.
Furthermore, it clearly states that the share of thermal power in the electricity mix should be reduced
from around 76% in fiscal 2019, to around 41% (LNG-fired: 20%, coal-fired: 19%, oil-fired: 2%) by
fiscal 2030.
Realizing these projections is expected to result in a 45% reduction in energy-derived CO2(including industrial, business, household, and transportation sectors) from fiscal 2013 levels.
Assuming that emissions from the energy conversion sector will be reduced by 47% by 2030, andbased on an average CO2 intensity of 552 g-CO2/kWh*7 for electricity in Japan as of fiscal 2013,
emissions intensity will fall to 292.6 g-CO2/kWh by 2030. Meanwhile, if we apply the CO2 intensity of
470 g-CO2/kWh for the electricity sector as of fiscal 2019, which is the standard base year adopted
by the international community for achieving net-zero emissions, a 50% reduction would mean 235

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g-CO2/kWh. However, if we align ourselves with the global standard and apply the CO2 emissions
intensity of 138 g-CO2/kWh for the global power generation sector in 2030, which is consistent withachieving the 1.5°C target as estimated by the above-mentioned international institutions such as
the IPCC and IEA, the power sector in Japan will be expected to set CO2 reduction targets that areeven more ambitious than current targets as set by the Japanese Government.
*6: The sector that converts primary energy, such as coal and oil, into secondary energy, such as electricity*7: Federation of Electric Power Companies of Japan: https://www.fepc.or.jp/english/environment/global_warming/index.html(Reference) Comparison of CO2 Emissions Intensity and Decarbonization Scenario for the Power
Sector (g-CO2/kWh)Scenario

2019

2030

2040

IEA Net Zero (Global)

468

138

0

Sixth Strategic Energy Plan (Japan)

470

293

—

2050
0

Positioning and Sustainability of Biomass Power Generation
In the Transition Roadmap for the Power Sector, released by the Agency for Natural Resources andEnergy in December 2021, promotion of biomass power generation constitutes an important part ofinitiatives for zero-emission thermal power generation, which also includes hydrogen, ammonia,
CCUS utilization, and other means.
On the other hand, fuel costs account for the majority of biomass power generation costs.
Therefore, the Sixth Strategic Energy Plan notes that the challenge of expanding the introduction of
biomass power generation lies in reducing fuel costs while ensuring stable procurement andsustainability of limited biomass fuel. The key measures include establishing quality standards forwoody biomass fuels to stimulate market transactions, reducing fuel costs, and ensuring the stabilityof the forestry business. In addition, to ensure the sustainability of biomass fuels, the FIT/FIP system
requires using fuels that meet sustainability standards formulated by conducting specialized andtechnical discussions from the perspectives of the environment, society, labor, and governance, as
well as compatibility with food supply and demand, and life cycle greenhouse gas emissions. The
method of confirming the sustainability of biomass fuels involves clarifying the evaluation criteria forobtaining third-party certification and requires supply chain traceability from the point of origin to
the power plant for main products, and from the point of origin of the fuel to the power plant for coproducts.

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4. Short-, Medium-, and Long-Term GHG Emission Reduction Targets and Indicators Consistent with
the Paris Agreement
For the transition of the power generation project, it is important to set targets consistent with thegoal of pursuing the Paris Agreement’s best-effort target of limiting global temperature rise to lessthan 1.5°C above pre-industrial levels. Since the current emissions intensity of East No. 3 is higher
than the CO2 emission intensity of the entire power sector as of fiscal 2019, the first step is to lower
the CO2 emissions intensity as soon as possible after the start of commercial operations, with due
consideration for economic feasibility and viability. If the biomass co-firing ratio is raised from thecurrent 20 cal% to 29.3 cal%, which is the upper limit under the FIT system, the CO2 emissions
intensity of East No. 3 is expected to decrease by approximately 11% from 592 g-CO2/kWh to 525 gCO2/kWh. In addition, further improvement in the co-firing ratio can be achieved by switching tousing black pellet (BP) biomass, which is relatively higher in calorific value and combustibility and issuitable for mono-fuel combustion. Based on a rough estimate, the CO2 emissions intensity at East
No. 3 can be reduced by approximately 33% from levels at the start of commercial operations byincreasing the biomass co-firing ratio to 50 cal% over the medium term.*8
As a medium- to long-term target for 2030, in addition to a biomass co-firing ratio for BP of at least
50 cal%, if the ammonia co-firing ratio can be raised to at least 20 cal% and coal consumption is kept
below 30% of calorific value to the extent possible, it is estimated that emissions at East No. 3 will be
reduced by at least 50% compared to levels at the start of commercial operations (assuming thathigher co-firing ratios for zero-emission ammonia is technically established through ongoingverification projects currently overseen by the Ministry of Economy, Trade and Industry and others).
In order to meet the higher levels of CO2 reduction required by international climate scenarios,achieving net-zero emissions by 2040 will be the long-term goal for East No. 3, assuming that highlevels of biomass-ammonia co-firing will be verified and established from a technological standpoint.
Where the introduction of biomass-ammonia co-firing technology significantly impairs businessprofitability, the use of highly reliable carbon credits and the introduction of bioenergy and CCS
technology will also be considered for achieving the target.
CO2 Emission Reduction Targets for Achieving Net-Zero Emissions at East No. 3
PeriodMeasures

Emission Factor Estimates

Reduction rate

At start of operations

Operate at WP co-firing ratio of 20

592 g-CO2/kWh—(September 2022)

cal%

Short term

Increase WP co-firing ratio from 20

525 g-CO2/kWh

11%(2022 to 2023)

cal% to 23 cal% and introduce BP at
co-firing ratio of around 6 cal%toward achieving biomass co-firing

9

ratio of 29.3 cal%, the upper limit of
FIT; prepare for verification,
procurement, and operation forswitch to BP
Medium term (2025)

Increase BP co-firing ratio to 50 cal%380-410 g-CO2/ kWh

Maximum 33%<292 g-CO2/ kWh*

50% or higher

0-CO2/kWh*

100%(or WP-BP co-firing ratio of 50 cal%);prepare plans for ammonia
procurement and verification
Medium to long term

Operate at BP co-firing ratio of 50(2030)

cal% (or WP-BP co-firing ratio of 50
cal%), operate at ammonia co-firingratio of at least 20 cal% (fuel ratio tobe adjusted based on performanceadvantage)

Long term (2040)

Operate at BP co-firing ratio of 50
cal% (or WP-BP co-firing ratio of 50
cal%), operate at ammonia co-firingratio of 50 cal% (fuel ratio to be
adjusted based on performanceadvantage)*Note: The emissions intensity of co-firing ammonia with BP at co-firing of over 50 cal% is estimated basedon the assumption that each 1 cal% increase in the biomass-ammonia co-firing ratio is equivalent to a 1%
reduction in emissions intensity. The above figures require verification by the plant manufacturer.

*8: Estimated value confirmed based on hearing conducted with MHI engineers. Since it will be difficult to achieve a biomass cofiring ratio of 50.0 cal% by operating the plant based on specifications for existing equipment, verification will be required based on
specifications for boiler performance after modifications are made to the facility.

5. Business Transformation Roadmap for Achieving Zero Emissions at East No. 3 power plant
The target values of the transition roadmap for this power generation project indicate a pathway forrealizing carbon neutrality in the power sector by 2040 in line with international scenarios and are
based on the following premises.
Given the possibility that operating East No. 3 with a biomass co-firing ratio of above 20 cal%may create constraints on individual equipment, no such constraints should in practice occur,and even if they are present, additional capital investment should not pose any technical or10business feasibility issues.
Given that increasing the biomass co-firing ratio from around 30 cal% to 50 cal% may require
modifications to current facility specifications for East No. 3, additional capital investment costs
and fuel conversion to biomass should not significantly impair the profitability of the project.
In the medium to long term, in addition to biomass co-firing, the technology for feedingammonia into thermal power plants at a ratio of at least 20 cal% should be verified andestablished by 2030.
Given the long-term goal of achieving zero emissions for this power generation project by 2040,
stable procurement of biomass and ammonia (either blue or green) should be ensured, and theeconomics of biomass-ammonia co-firing should improve.
CO2 emissions from biomass fuel combustion are not included in the calculation.
Future Considerations for Business Transformation
The following considerations should be taken into account to achieve the above reduction targets.
Given that the upper limit of the WP co-firing ratio may be around 23 cal%, as opposed to theplanned increase in the WP co-firing ratio from 20 cal% to 29.3 cal%, adjustments to equipment
and verification should be implemented to enable procuring BP for the remaining biomass
volume and feeding it directly into the coal mill.
Needs and costs of equipment modification/retrofitting to accommodate BP input and otherissues (to be confirmed with the manufacturer)
Cargo handling, yard, port facilities, conveyors, coal and biomass mills, boilers, dust
collectors, handling covers, cooling systems for controlling dust explosion, and otherequipment
Modifications to equipment required for increasing the biomass co-firing ratio from 29.3
cal% to at least 50 cal% based on BP input
Confirm volume and costs of procuring BP, as well as quality and traceability (LCA of GHG
emissions, including sourcing origin and supply chain) (to be confirmed with fuel suppliers)
・ Identification of BP suppliers and origin
・ BP quality assurance (including environmental and forest certifications and third-party
certification for legality and sustainability)
・ BP procurement costs
Equipment modifications for accommodating ammonia and related issues (to be confirmed withthe manufacturer and fuel suppliers)
・ Technical feasibility
・ Facility remodeling and renovation, infrastructure development
・ Financing

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Outlook on ammonia procurement volume, environmental performance, and costs (assuming asurvey is conducted by fuel providers and external agencies)
・ LCA of GHG emissions from the ammonia manufacturing process of suppliers (use ofrenewable energy sources, natural gas, and other sources)
Analysis of economic rationality of biomass-ammonia co-firing (assuming research by external
agencies)
Relationship to peripheral businesses and operations
・ Positioning within TK’s factory
・ Positioning within industrial complexes in the Shunan area
・ Progress in the carbon neutral port project at Tokuyama-Kudamatsu Port, and potential forcollaboration
・ Possibility of participation in METI’s verification project on ammonia co-firing at East No. 3
Investment Plan for the Transition Roadmap
Phase and Content

Equipment to Be Considered for Investment

Implementation
PeriodPhase 1—

FY2022

Maximize co-firing ratiousing WP at the current
facility (assuming 22–23
cal%)Phase 2Equipment* required for additionally procuring

Introduce BP to increase

BP and directly feeding it into the coal mill tothe co-firing ratio to 29.3

achieve the 29.3 cal% biomass co-firing ratio

cal% (upper limit ofbased on the results of Phase 1 (including

biomass co-firing ratio

modification and verification of cargo handling,under FIT)

yard, port facilities, conveyors, coal and biomass

FY2023–FY2024

mills, boilers, dust collectors, handling covers,and cooling systems for controlling dust
explosion)*Actual equipment requirements and costs must be
confirmed with the manufacturer and relevant stakeholders.

Phase 3Equipment required for additionally procuring

Aim to raise biomass co-

BP and directly feeding it into the coal mill tofiring ratio to 50 cal% orachieve the 50 cal% biomass co-firing ratio

higher by increasing thebased on the results of Phase 2 (including

FY2024–FY2025

12

BP co-firing ratio

modification and verification of cargo handling,
yard, port facilities, conveyors, coal and biomass
mills, boilers, dust collectors, handling covers,and cooling systems for controlling dust
explosion)*Actual equipment requirements and costs must be
confirmed with the manufacturer and relevant stakeholders.

Phase 4

Begin analysis and research on technicalAim for ammonia co-firing

feasibility studies and business profitability toratio of 20 cal% inachieve ammonia co-firing ratio of 20 cal% in

addition to biomass co-addition to biomass co-firing ratio of at least 50

firing ratio of 50 cal% or

cal%, consult with plant manufacturers, fuelhigher (coal: 30 cal% or

suppliers, and related stakeholders regarding

less)necessary facility modifications, infrastructure

FY2026–FY2030

development, and funding, and implement
modification plans and verification tests todetermine whether commercial operation ofammonia co-firing is possible.**Content regarding the technical feasibility of high-levelammonia co-firing will be revised as needed and based onprogress of government verification projects and otherdevelopments.

Phase 5Equipment including high-level ammonia co-

In addition to achieving

firing and mono-fuel combustion burners forbiomass co-firing ratio of

realizing biomass-ammonia co-firing at ratios of

50 cal%, aim to operate at

50 cal% each, or mono-fuel firing of either

ammonia co-firing ratio of

biomass or ammonia based on the results of

50 cal% (coal: 0-cal%)verification in Phase 4; equipment for fuelprocurement, transportation, supply andstorage, and equipment required for achieving
zero emissions at East No. 3

To FY2040