Advisory Committee for Natural Resource and Energy
Strategic Policy Committee
Some additional data is added
May 13th, 2021
to the original material. (Ver.
June 11th, 2021)

Scenario Analyses for 2050 Carbon Neutrality
in Japan (Interim Report)
Keigo Akimoto, Fuminori Sano
Systems Analysis Group
Research Institute of Innovative Technology for the Earth (RITE)

Acknowledgement: We thank Dr. Yuji Matsuo, the Instituteof Energy Economics, Japan, for his cooperation on the
integration cost analysis of power grid.

1. Overview of Climate Change
Mitigation for Carbon Neutrality

Image of Primary Energy in Japan
for Net Zero Emissions (1/2)

3【Domestic primary energy supply】
Energy saving or Reductionin embodied energy of goods/services(incl. Society 5.0)

 The model analyses
represent consistent energy
structures and costs which
are economically rationalizedwith cost minimization underassumed conditions oftechnologies.

【Use of overseas resources】
Nuclear

Nuclear
Domestic renewables

DecarbonizedenergyRenewable energy

Measures of grid to expand
renewables (incl. storage battery)Use of renewables surplus
for hydrogen

Use of overseas renewables (green Sys. fuels prone to be generated fromfossil fuels if the constraint on CO2 ishydrogen) (import of hydrogen,loose in the producing countries, whilefrom BECCS or DAC (with increased
ammonia, and syn. fuels (CCU))
cost) if the constraint is strict.
Use of overseas CO2 reservoir (pre-combustion CO2
capture) (import of blue hydrogen (incl. ammonia))

Fossil fuels + CCS

Remainingfossil fuels【Assessment Scenarios】
 The limit on nuclear power isassumed as a social constraint.
 The constraint of CO2 storage
potential is also assumed.
In this case, the ratio among domestic
renewables, overseas hydrogen /ammonia / syn. fuels is derived withcost minimization criterion (thesolution suggested by the model is
not so flexible).

Fossil fuels w/CCS
Fossil fuels
w/o CCS

Domestic CO2 storage

BECCS, DACCS

Use of overseas CO2
reservoir (postcombustion)

Forestation, mineralization (concrete CCU)

Negative emission technologies (NETs)【Use of overseas
resources】

Image of Primary Energy in Japan
for Net Zero Emissions (2/2)

4 The whole system including non-electric power sectors is analyzed in the model.
 Electricity generation amount is determined by combined factors such as followings: energy demandchange induced by social structural change (basically although it depends on socio-economic
pathways] + [electrification increase by energy usage structural change ( )] + [demand decrease bypower saving ( )] + [electrification of non-electricity demand ( )] + [increase of loss in increased
power storage, e.g., storage battery, due to VRE expansion ( )] + [increase of electricity demand to
produce green hydrogen and e-fuels (syn. fuels) ( ) (however, electricity demand in Japan would not
be affected in case of overseas manufacturing)].
2018
1.06GtCommercial/Residential
0.11GtNonelectricity

Industry
0.3Gt

Transport
0.2Gt

2030
0.93Gt (▲25%)2050
Net-zero emission(▲100%)

Residential & Commercial
0.09GtElectrification

Industry
0.33GtTransport
0.15GtHydrogen (hydrogen-based
reduced iron, FCV, etc.)

Methanation, syn. fuels

Biomass

Non-fossil sources
Electricity

0.45Gt

0.36GtCarbonremoval
Source) Strategic Policy Committee, Advisory Committee for Natural Resource and Energy, 2020

Renewables
NuclearThermal + CCUS /Carbon recycle
Hydrogen / Ammonia

Maximize CCUS / carbon
recycle, etc. in the sectors
where decarbonization byelectrification / hydrogenation
is not possible.

Forestation,
DACCS, etc.
* The figures indicate CO2 from energy sources.

2. Assessment using Global Energy
and Climate Change Mitigation
Model: DNE21+

The model-driven scenarios represent quantitative features of energy and global
warming response measures which are globally consistent in a given time-frame
under assumed conditions, and specify the energy systems which are economicallyrationalized with cost minimization.

Energy Assessment Model: DNE21+(Dynamic New Earth 21+)6



Systemic cost evaluation on energy and CO2 reduction technologies is possible.

Linear programming model (minimizing world energy system cost; with 10mil. variables and10mil. constrained conditions)

Evaluation time period: 2000-2100
Representative time points: 2005, 2010, 2015, 2020, 2025, 2030, 2040, 2050, 2070 and 2100

World divided into 54 regions
Large area countries, e.g., US and China, are further disaggregated, totaling 77 world regions.

Interregional trade: coal, crude oil/oil products, natural gas/syn. methane, electricity, ethanol,hydrogen, CO2 (provided that external transfer of CO2 is not assumed in the baseline)

Bottom-up modeling for technologies on energy supply side (e.g., power sector) and CCUS

For energy demand side, bottom-up modeling conducted for the industry sector including steel,cement, paper, chemicals and aluminum, the transport sector, and a part of the residential &commercial sector, considering CGS for other industry and residential & commercial sectors.



Bottom-up modeling for international marine bunker and aviation.



Around 500 specific technologies are modeled, with lifetime of equipment considered.

Top-down modeling for others (energy saving effect is estimated using log-term price elasticity.

••

Regional and sectoral technological information provided in detail enough to analyze consistently.
Analyses on non-CO2 GHG possible with another model RITE has developed based on US EPA’s assumptions.
•

Model based analyses and evaluation provide recommendation for major governmental policy making on
climate change, e.g., cap-and-trade system and Environmental Energy Technology Innovation Plan, andalso contribute to IPCC scenario analysis.

Technology Descriptions in DNE21+

7

Oil prices in baseline assuming no climate measures are exogenously assumed,
and other price factors, e.g., unit production costs, concession fees, are adjusted.
In emission reduction case, prices are endogenously decided accordingly.

Fossil fuels
Coal (coal, lignite)
Oil (conventional, unconv.)
Gas (conventional, unconv.)
Unit
production
costEnergy conv.
processes(oil refinery,coal gasification,
bio-ethanol,gas reforming,
water electrolysis,etc.)ElectricPower
generation

propylene, ammonia)

Transport
Vehicle, shipping, aviation
Solid, liquid and gaseous fuels,and electricity

Unit
supplycost

Residential & Commercial

CCUS

Nuclear power
Facility cost and efficiency ofeach technology are
exogenously assumed.

Paper & pulp
Chemical (ethylene,

Solid, liquid and gaseous fuels,and electricity

Renewable energies

Annual production

CementAluminum

Cumulative production

Hydro power & geothermalWind power
PV / CSP
Biomass, Marine energy

Industry
Iron & steel

Air conditioner, refrigerator, TV,
etc.
Solid, liquid and gaseous fuels,and electricity

DAC

For main sectors
modeled in abottom-up way,
economic
activities andservice demands(e.g., productionof crude steel
and cement,
passenger
service demand)are exogenously
assumed.

Limitation and Challenge of the Model

8

In DNE21+ model, which enables the assessment of the whole world with consistency
regarding energy import / export amounts and prices, the prerequisites are assumed
considering consistency in the global system. Regarding the assumption for PV, wind
power generation and CO2 storage potential, for instance, the potentials for each country
are assumed using a common assumption logic based on the global GIS data.



Therefore, it is suitable for the comparison and assessment of technological andeconomic potentials among countries while it does not significantly consider countryspecific circumstances (e.g., social and physical constraints on nuclear power andrenewable energy in Japan).

In-depth analyses for Japan should be conducted separately taking into account moredetailed conditions. For instance, the domestic power grid structure is not specified in
DNE21+, making difficult to assess the differences in system costs depending on the
renewable energy installation sites.
Analysis results of Power Generation Mix Model by Univ. of Tokyo and IEEJ is utilized.



As DNE21+ is a dynamic optimization model, it can provide assessment for time points,
e.g., 2050, in accordance with the future features in 2100. Also, any arbitrary scenario
assumption is supposed to be excluded as the assessment is made based on a cost
minimization criterion. On the other hand, the model could show extreme changes, e.g.,
all the predicted technologies are replaced with others once economic rationality iscompleted. (The real world usually follows a technology diffusion curve without extremechanges as there are various actors. Compared to macro econometric models, which issuperior for representing such situations, this type of optimization models could
sometimes show extreme changes.)Assumption of Integration Cost:
Power Generation Mix Model by Univ. of Tokyo and IEEJ

9

 As DNE21+ is a global model and not suitable for the analysis regarding internal power grid andregional conditions of renewable energy, it applies the results of the study on the assumption of
integration cost under high VRE penetration based on an optimal power generation mix model, by FujiiKomiyama Laboratory, the University of Tokyo and the Institute of Energy Economics, Japan1), 2).
 Time fluctuation of VRE output is modeled based on nationwide meteorological data, e.g., AMeDAS, toestimate the optimal configuration (power generation and storage system) and the annual operation bylinear programming.
 Calculated with hourly modeling by 5 divided regions (Hokkaido, Tohoku, Tokyo, Kyushu and others).

Prerequisites for power generation cost, resource constraint, etc, are defined in line with DNE21+.
Considered in modeling・・・ Output control, power storage system (pumped hydro, lithium-ion battery and hydrogen storage),
reduction of power generation facility utilization, inter-regional power transmission lines,
electricity loss in storage and transmission
Not considered in modeling・・・ Intra-regional power transmission lines, power grid, influence of decrease of rotational inertia,
grid power storage by EV, prediction error of VRE output, supply disruption risk during dark doldrum

Output example of PV
Meteorological data
（AMeDAS: 1300 nodes）

Output example of wind power

1) R. Komiyama and Y. Fujii, (2017). Energy Policy, 101, 594-611.
2) Y. Matsuo et al., (2020). Applied Energy, 267, 113956.

Acknowledgement: We thank Dr. Yuji Matsuo, the Institute of Energy Economics, Japan, for his cooperation.

Prerequisites and Assumptions in DNE21+ Model (1/4)
10SectorAssumption method

ExampleSupplementary

Population

UN median estimate

Refer toappendixGDP

Estimated by country based on assumed
population, GDP per capita, etc. Consistent with
IPCC SSPs scenarios.

As DNE21 is an energy systemmodel, population and GDP areexogenous and used for theassumption such as for service
demand.

Refer toappendix for
selected
sectors

Service demand can besignificantly reduced in the casethat GDP losses are huge due tohigh costs of emission reduction orthat there are large differences incountermeasure cost among
nations. It should be noted that the
feedback in such cases are notconsidered in DNE21+ as it is apartial equilibrium model.

Servicedemand,etc.

Iron & steel,
Cement,Chemical,Paper & pulp
Aluminum,Roadtransportation,
Domestic
aviation,International
aviation,International
marine bunker

Assumed by country / region divided in the model
based on past records, population, GDP, etc.
For iron & steel, total production of crude steel isassumed, and also, as its internal number,electric furnace steel production assumed basedon the available iron scrap estimate.
For chemical, ethylene, propylene, BTX andammonia are assumed.
For road transportation, demands are assumed
by car (small and large), bus and truck (small andlarge).
For aviation, demands by 4 flight zones are
assumed.

Prerequisites and Assumptions in DNE21+ Model (2/4)
11

SectorFossil fuelBiomass

Assumption method

ExampleAmount ofresources

Based on the reports of United States Geological Survey(USGS) for oil / gas, and World Energy Council (WEC)(Survey of Energy Resources 1998) for coal.
Assumed from the article by H-H. Rogner (1997) for
unconventional oil / gas.

Globally, conventionaloil (incl. NGL): 241
Gtoe, conventional
natural gas: 243 Gtoe,
coal (incl. lignite):
2576 Gtoe, etc.

Price

Based on the article by H-H. Rogner (1997) for mining
cost. FOB price in baseline scenario is adjusted asconcession fee referring to IEA WEO, etc.

Refer to appendix

Residue

Food residue and wood residue are estimated by country.

Potential in 2050 isabout 9EJ/yr globally.

Plantation andforestation
potential

Using RITE GLaW (Grid-based model for agriculturalLand-use and Water resource assessment) model,
potentials are estimated for food production according tofood consumption and meteorological forecast, land-use
areas and surplus land. Potential for plantation biomass(and forestation) is estimated.

About 900 Mha isavailable in 2050
globally.

Several production technologies are assumed, such as
produced from fossil fuel (grey hydrogen), fossil fuel +CCS (blue hydrogen) and by renewable energy (greenhydrogen), and the model endogenously decides the one
with minimized cost under the emission reduction target.
Transportation cost is modeled referring to a reported
case of liquid hydrogen transportation cost, provided that
long-distance transportation is not specified.

Refer to appendix

Hydrogen

Synthetic
fuel (CCU)

Petroleum-based synthetic oil and synthetic methane
are assumed. CO2 from biomass, DAC, and fossil fuel isassumed. The model endogenously decides the one withminimized cost under the emission reduction target.

Supplementary

For methanation,
Sabatier reaction and
SOEC co-electrolysis
are assumed.

Prerequisites and Assumptions in DNE21+ Model (3/4)
12SectorPower
generation

CCS

Assumption method

ExampleFossil /biomass

Facility cost is assumed based on the reports of
OECD/NEA, cost verification committee, etc. For fuel cost,based on FOB price described in the fossil fuel price, CIF
price considering transportation distance is assumed.

Refer toappendix

Nuclearpower

Facility cost is assumed based on the reports of
OECD/NEA, cost verification committee, etc.

Refer toappendix

For countries not planning to adopt
nuclear power, no deployment isassumed regardless economic
efficiency. For Japan, in line with the2030 energy mix as 20% nuclear power,
the upper limit is set as 10% in
Reference case. Sensitivity is analyzed.

Renewableenergy

PV: Grid-based potential is estimated based on insolation
data and land use data of NASA GIS.
Wind power: Grid-based potential is estimated based onwind speed data and land use data of NOAA GIS.
For VRE, grid costs are assumed as rising as the VRE
ratio in total power generation increases (using Powergeneration mix model by Univ. of Tokyo and IEEJ).
Hydro power: Cost and potential are assumed by country
based on WEC Survey of Energy Resources 1998.
Geothermal power: Assumed generation cost as
172$/MWh-258$/MWh based on several literature.
CSP: Grid-based potential is estimated based on
insolation data and land use data of NASA GIS.

VRE: p.24-30

Assumption is made from GIS data
based on a world atlas for global
consistency.
The scenario that facility cost is reduced
over time is exogenously assumed.
More precise data for Japan regarding
GIS accuracy, land use cost, etc. should
be further examined.

CaptureFacility cost and energy to capture CO2 are assumed
based on several literature.

Refer toappendix

Transport

Pipeline and liquid CO2 transportation (tanker) are
assumed.

Refer to p.34

Assumption is made from GIS data
based on a world atlas for global
consistency.
More precise data for Japan should befurther examined.

Storage

Storage potential is estimated based on geological data of
United States Geological Survey (USGS). (Refer to
Akimoto et al., IEA GHG, 2004.)

Direct Air Capture of CO2(DAC)

Based on M. Fasihi et al., (2019), which conducts many
surveys on DAC, facility cost and energy amount for
capture of 2 systems are assumed.

Refer toappendix

Supplementary

For captured CO2, same as transportand storage in CCS. For CCU use,same as synthetic fuel.

Prerequisites and Assumptions in DNE21+ Model (4/4)
13

SectorAssumption method

ExampleSupplementary

Iron & Steel

Energy saving technologies (e.g., COURSE50), CCS, gas-based
DRI, and H2-based DRI are assumed. Facility cost and energybalance are assumed referring to several literature (J. Oda et al.,Energy Economics, 2007, etc.).
The installation amount of electric furnace is constrained according
to availability of scrap iron.

Refer to appendix foravailability of H2-based
DRI and scrap iron.

By BF-BOF + CCS,
about 30% CO2
emission reduction ispossible, but net-zeroemission is notpossible.

Cement /Concrete

Energy saving technologies, conversion from coal to gas, hydrogenor synthetic methane, CCS (only available above 3000 t-clinker/day)are assumed, which are endogenously determined with total
optimization. Facility cost and energy balance are assumed referring
to several literature. Concrete CCU is assumed.

Concrete CCU

ChemicalMethods to produce ethylene, propylene, BTX and ammonia are
assumed, as well as energy saving technologies for each. Productionof ethylene and propylene from ethane, and production of ethylene,
propylene and BTX via methanol (produced from hydrogen and CO2(CCU)) are also assumed.

Residential&
Commercial

Residential &Commercial

Assuming demands for refrigerator, lighting, cooking equipment, hotwater supply and cooling & heating, various equipment, e.g., heatpump and cogeneration, is modeled. City gas infrastructure cots is
also assumed.

Transport infrastructure
cost to convert from city
gas to hydrogen is
assumed as twice as fromgas and syn. methane.

Transport

Road
transportation

Conventional engine car (gasoline, light oil and bio fuel), HV, PHV,EV and FCV are assumed by vehicle type (passenger car (small /large), bus and truck (small / large)). Car body price is assumed
referring to sales price and cost reduction outlook. Additional costs
for infrastructure for EV and FCV are assumed (hugely decreasing
toward 2050). Syn. Fuels are assumed. Share mobilities (car-/ridesharing) scenario induced by fully autonomous car is also assumed.

Refer to appendix for theexample of small
passenger car.
Refer to p.36 for car-/ridesharing scenario
assumption.

Aviation

Energy saving, transition of jet fuel to biofuel / syn. jet fuel, hydrogen
aircraft and electric aircraft are assumed. The scope thattechnologies can meet the demand by flight zone is assumed. Fuelcost is endogenously determined in the model. Aircraft cost is
assumed referring to several literature.

International
marine bunker

Heavy oil, light oil, biodiesel fuel, LNG carrier and hydrogen ship areassumed.

Industry

Max. 1.9kgCO2/t-cement(net absorption considering
the CO2 amount by natural
absorption is modeled.)

It is assumed that fullyautonomous car isavailable in 2030 inshare mobilities
scenario.

Global Baseline Emissions andAssumed Emissions Scenarios under 2C and 1.5C80

CO2 emissions
Net zero CO2 emissions
around 2050

60
CO2 emissions [GtCO2/yr]

14

40

Net zero CO2 emissions
around 2060

20

0

-20

-40
2000

Net zero CO2 emissions
around 2100
Historical
Baseline

Net zero GHG emissions
around 2065

2DS(▲40% GHG in 2050)
B2DS(▲70% GHG in 2050)
Below 1.5℃ in 2100 (>66%)
2010

2020

2030

Net zero GHG emissions
around 2100
2040

2050

2060

2070

2080
120

Note) Emissions for baseline shows model estimates
results under SSP2, not assumed scenario

In the scenario analyses of Japan’s 2050 carbon neutrality,
1.5C global scenarios are assumed in addition to Japan’semissions reduction scenarios, for the global competition
for carbon neutral resources to be considered.

GHG emissions [GtCO2eq/yr]※ 2DS, B2DS, B1.5OS scenarios assume
emission constraints equivalent to NDCs ofeach nation up to 2030

100
80

2090

2100

GHG emissions

Historical
Baseline
2DS(▲40% GHG in 2050)
B2DS(▲70% GHG in 2050)
Below 1.5℃ in 2100 (>66%)

60
40
20
0
-20
2000

2010

2020

2030

2040

2050

2060

2070

2080

2090

2100

3. Assumed Scenarios

Overview of Assumed Scenarios
16

GHG
emission
reductionin 2050

Technology
assumption(cost / performance)

Technology deployment scenario

Reference case

▲100%Standard case

Assuming high share
RE in model’s
standard assumption
under Reference case

(For otherthan Japan,▲100% foreach westerncountry, and▲100% forthe others asa whole)Decided endogenously (costminimization), with constraints fornuclear power up to 10% and CO2 storage.

(Note: It is premised that
RE is diffused due tosuspected inertial force inhigh share RE scenario.)

Assuming eachtechnology is further
accelerated or
expanded.

1
Renewable Energy
100% (RE100)

Renewable energy nearly 100%
(Nuclear power 0%)

Acceleration of RE
cost reduction

Decided endogenously, with constraints
for nuclear power up to 10% and CO2
storage.

3
Nuclear Power
Utilization

Expansion of
nuclear power
deployment

Decided endogenously, with constraints
for nuclear power up to 20% and CO2
storage.

4
HydrogenInnovation

Acceleration ofhydrogen cost
reduction

Decided endogenously, with constraints
for nuclear power up to 10% and CO2
storage.

5
CCUS Utilization

Expansion of CO2
storage potential

Decided endogenously, with constraints
for nuclear power up to 10%. Large CCS
storage potential assumed.

Expansion of car/ride-sharing

Dramatic expansion of car-/ride-sharing
due to fully autonomous car
implementation assumed.
Other assumptions are same as
Reference case.

2
Renewable Energy
Innovation

6
DemandTransformation*As for demand side transformation, scenario analyses will be continued including other factors than car-sharing.

Scenario Description in Modeling Analyses (1/4)
Scenario

Challenges to realize scenario<Renewable energy>(1) Securing load balance
For VRE expansion, need to secure demand & supply balance tocope with output fluctuation due to natural conditions.

Model Input<Renewable energy>
Assumption for stable grid operation•(2) Securing transmission capacity

Reference
case

Scenario in
which thechallenges ofeach powersource to realize
Reference case,presented fordeeperdiscussion in the
35th Strategic
PolicyCommittee, areovercome.
Image of power
generation mix
RE 50-60%,
Nuclear power
10%, Hydrogen /Ammonia 10%,
CCUS thermal
20-30%
Determined in
the model withcost minimization

Need to promote large-scale capital investment and local consensus
for construction to increase the transmission capacity that connects
areas potential for deployment of renewables and areas in demand.

(3) Securing inertial force
Need to secure a constant “inertial force” (to keep turbines rotating)in an entire system to prevent blackout due to accidents such as
power loss.

(4) Response to natural conditions and social constraints
For RE expansion under disadvantageous natural conditions interms of insolation and wind, e.g., flat land excluding forests is halfthat of Germany and shallow sea area is 1/8 that of the UK, needcoordination with local community and concerned parties,
considering the impact on environment, ecosystem, shipping routes,
etc.

17

Assuming VRE expansion by overcoming the challenges,
such as securing power demand & supply balance,
securing transmission capacity to deal with unevenness
of RE suitable sites, and securing inertial force in an
entire system to cope with blackout in case of power loss.

Assumption for deployment based on natural /physical conditions••

Assuming power generation amount above the current
Germany’s (about 640TWh) and above 2 times of UK’s
(about 330TWh) under limited natural conditions.
Assuming power generation amount based on the casethat solar and offshore wind power deployment expands
by installing PV on rooftops or in abandoned croplands
and utilizing Act of Promoting Utilization of Sea Areas.

Economic assumption•(5) Cost
Additional costs can be required for land preparation, connection
and coordination if the deployment amount increases under thegeographical conditions such as scarce flat land and shallow sea.
Need to reduce the total RE deployment costs by securing suitablesites and developing highly efficient power generation equipment.

Assuming that capital cost and O&M cost be reduced
according to the international price as securing suitablesites progresses with the current technological level(provided that cost increase due to location restriction is
not precisely considered).
Assumed power generation costs are PV: ¥10-17,
wind power: ¥11-20 and integration cost: about ¥4.

<Nuclear power>(1) Restoring public trust<Nuclear power>
Assumption for sustainability

Need to restore public trust through pursuing safety, coexisting withlocal community, establishing sustainable back-end system,
improving feasibility, maintaining and strengthening humanresources / technologies / industrial bases, and working on nuclear
power innovation.

•(2) Securing installed capacity

Economic assumption

The installed capacity of nuclear power will decrease significantly
after 2040 to be 23.74GW (166.3TWh) (about 10% of power
generation mix) in 2050, and 9.56GW (67TWh) in 2060, evenassuming that all 36 nuclear plants (incl. under construction) operate
for 60 years. Need to secure installed capacity.

•

Assuming power generation amount in the conditions that
nuclear power is continuously utilized on a certain scaleand new reactors are commissioned by tackling issues
such as safety improvement, final disposal site problem
and nuclear fuel cycle.
For power generation cost, the global standard is used on
the premise of the current technological level.
Power generation amount is constrained up to 10% of
the power generation mix considering social restrictions.
Assumed power generation cost is ¥13, same as global
standard .

Scenario Description in Modeling Analyses (2/4)
Scenario

Challenges to realize scenario<Hydrogen / Ammonia>(1) Supply side

Reference
case

Scenario in
which thechallenges ofeach powersource to realize
Reference case,presented fordeeperdiscussion in the
35th Strategic
PolicyCommittee, areovercome.
Image of power
generation mix
RE 50-60%,
Nuclear power
10%, Hydrogen /Ammonia 10%,
CCUS thermal
20-30%
Determined in
the model withcost minimization

Model Input<Hydrogen / Ammonia>
Assumption for technological development

Considering supply is highly likely prioritized in the sectors where
electrification is difficult, such as industrial, residential & commercial, andtransportation, need to secure about 20Mt of hydrogen in Japan.

•

If domestic procurement is not enough, need to develop transportation
technologies and port facilities for large-scale and low-cost import.

Assumption for large-scale procurement•(2) Demand side
In developing combustors to ensure stable combustibility of hydrogenand ammonia power generation, need technological development toensure suppression of NOx generation and stable combustibility.
For expanding demand & supply of hydrogen and securing the supply
amount used for power generation, need to expand the demand in othersectors than power generation, e.g., FC truck and hydrogen ship intransportation and expanded usage in industry.

A major premise is to overcome technical issues forhydrogen / ammonia power generation.

On top of that, it is assumed that after being usedpreferentially in industrial / residential & commercial /transportation sectors, the supply greatly exceeding
the 2030 forecast should be secured. (LNG needs toincrease at a higher pace than quadruple
incremental rate of supply in 30 years from 1980s to
2010s.)

Economic assumption•(3) Cost
In the context that hydrogen supply chain has not been established,
need to reduce the costs of cargo bases and liquefied hydrogen carriersin addition to the costs required for hydrogen production and liquefaction.

Assuming manufacturing and transportation cost is
one fifth of about ¥170/Nm3 or less, on the premisethat inexpensive manufacturing equipment and a
global supply chain are developed.
Assumed power generation cost is ¥16-27.

<CCUS>(1) Technology / Cost

<CCUS>
Assumption for technological development

Need to develop efficient technology to separate and capture CO2,
establish low-cost CO2 transportation technology, and reduce storage
cost. Also, for practical use of carbon recycle, need cost reduction andapplication enhancement.

•

If domestic CCUS is not enough to handle, for transportation overseas,need to overcome further technical issues such as establishing shiptransportation technology for low-temperature and low-pressure liquefied
CO2, which is unprecedented in the world yet.

(2) Securing potential sites and expanding application
Considering CCUS is highly likely applied for electrification in industrial /residential & commercial / transportation sectors or for GHG emissions
from the sectors where utilizing hydrogen / ammonia is difficult, need tosecure substantial suitable lands and application development in order toutilize CCUS for power generation.

18

Overcoming technical issues for practical use of CCS
and carbon recycling, e.g., technology to improveseparation and storage efficiency, is a major premise.
Assuming the cost will be reduced to 70% or less ofthe current level through technological development.

Assumption for large-scale storage•

On top of that, it is assumed that after being usedpreferentially in industrial / residential & commercial /transportation sectors and for non-energy sources,
CCS will be implemented in excess of about 0.3Gt /year. In Reference case, assuming it possible totransport about 0.2Gt overseas.
Assumed power generation cost is around ¥12.
In Reference case, CCS storage potentials are 90
MtCO2 in domestic and 240 MtCO2 overseas.

Scenario Description in Modeling Analyses (3/4)
Scenario

Challenges to realize scenario

19

Model Input<Renewable energy>

1
Renewable
Energy100%

Scenario in whichcarbon neutrality isrealized with onlyRE.

In case that +40% (about 300TWh) or so of RE compared to Reference case is
implemented, in addition to further securing load balance, transmission capacity andinertial force, the following capacity needs to be deployed additionally on the premise of
the current technologies.
 If half of the capacity is realized by PV (about 150TWh) and another half byoffshore wind power (about 150TWh), the following amount is required.
 For PV, about 110GW (about 130TWh) is necessary in addition to Reference case.
If it is covered by 1 MW mega solar, additional 110,000 locations will be required,
meaning, for instance, that all of the approximate 1,700 municipalities need tosecure 65 sites on average additionally to the amount already deployed in
Reference case.
 For offshore wind power, the 2040 target amount of 45 GW (about 130TWh) is
necessary in addition to Reference case.
 The outlook for RE deployment in 2050 in the UK BEIS scenario* is about 400430TWh, and about 2.5-2.7 times this amount needs to be deployed in RE 100%case.

Image of power generation mix
RE 100%RE volumes are exogenously
assumed.
Power generation cost
Same as Reference case

* BEIS, Net Zero and the Power Sector Scenarios, 2020.12

2
Renewable
EnergyInnovation

Scenario in which
RE installation
expands due todramatic reductionof RE cost and withthe challenges ofgrid operation, e.g.,natural & physicalconstraints andinertial force,
overcome byinnovation, moresignificantly
compared toReference case.

<Renewable energy>
In order to realize further cost reduction than Reference case and tackle physical andsocial constraints, need to overcome technical issues through technological innovation,such as development and commercialization of innovative technologies, e.g., tandem
solar cell and perovskite solar cell, and wind power with significantly improved power
generation efficiency.
For overcoming the problem of inertial force, need to develop and implement a systemwith suspected inertial force and apply inertial force in power storage system.
Also, if +10% (about 130TWh) is deployed additionally to Reference case, need to
install the same RE setup as any shown in 1 Renewable Energy 100% case.

Image of power generation mix
RE 60-70%
Power generation cost
RE cost: PV ¥6-10,
Wind power ¥8-15
Same as Reference case for otherpower sources

Scenario Description in Modeling Analyses (4/4)
Scenario3.
Accelerated
utilizationof nuclear
power

4.
Dramatic
reductioninhydrogen/ammonia
prices5.
Dramatic
increasesin CO2
storage in
CCUS

A scenario in which
replacement and new
expansion are realized asa result of progressing
public understanding of
nuclear power andovercoming social andtechnical issues such as
ensuring safety andestablishing a back-end
systemA scenario in which
technological innovationsin the hydrogen production
and transportation process
significantly reduce prices
of hydrogen production
and transportation

A scenario in which theamount of transportation issignificantly increased bysignificantly expanding
domestic storage areas
through technologicalinnovation and overcoming
the challenges of overseas
transportation of CO2.

Challenges to realize scenario＜Nuclear power＞
If all 36 units have been in operation for 60 years, it will be about 10%. To further
increase it by 10%, approximately 20 new furnaces (20 million kW) are required
through replacement or new expansion by overcoming issues such as restoration of
public trust, understanding of local community, final disposal and establishment of backend systems such as the nuclear fuel cycle.

＜Hydrogen/ammonia＞
Assuming a reference value case in which manufacturing and transportation costs are
1/5 or less from the current level, it is necessary to further reduce these costs byfurther technological innovation and market expansion through expansion ofprivate investment.
In addition, if + 10% (about 130 billion kWh) is additionally introduced from the case of
the reference value, it is necessary to additionally procure 5 to 10 million tons ofhydrogen domestically or from overseas. If all are procured domestically, a total of 1,000
to 2,000 plants of the same scale as FH2R are required, and if all are procured fromoverseas, it is necessary to additionally secure about 90 vessels from the reference value,
in which the hydrogen loading capacity of the vessel (currently about 75 tons per vessel)
expands to about 100 times or more (about 10,000 tons per vessel) from the reference
value.
＜Thermal power generation with CCUS＞
Assuming a reference value case in which costs are less than half of the current level
because of technological development and market expansion, it is necessary to further
expand the storage capacity by further technological innovation and market
expansion through expansion of private investment.
In addition, if + 10% (about 130 billion kWh) is additionally introduced from the case of
the reference value, a total of 550 million tons of CCS storage is required. This meansthat a total of 600 drilling wells (injection rate of 500,000 tons / y per well) will be
required for domestic storage by 2050. Moreover, it is necessary to realize a scale of
CCS which is 900 times or more of the cumulative injection amount (300,000 tons inabout 3 years) of the Tomakomai demonstration project every year. In addition, about
300 CO2 transport vessels (assumed to be 20,000t-CO2 / vessel) are required foroverseas storage.

20

Model input
Power generation mix
Nuclear power: 20%
Power generation cost
Same as the Reference
Case
Upper limit
20% for nuclear power

Power generation mix
Hydrogen/ammonia: 20%
Power generation cost
Hydrogen price: ¥20 – 35
/Nm3 (Power generation
cost ¥13 – 21/kWh)Other than hydrogen, costs
are the same as Reference
CasePower generation mix
CCUS power generation:
30% - 40%
Power generation cost
Same as Reference Case
Upper limit
Domestic storage for CCS:
270 million tons,
Overseas transportation
volume expands to 280
million tons.

Scenario Assumption andShare of Renewables in Total Electricity(in 2050)
Scenario

Cost ofrenewableenergy2. Renewable
EnergyInnovation

Standard
cost

CCUS(Storage potential)

Share of RE in powermix
54%(Optimization results)

Domestic
storage:91MtCO2/yr,
Overseastransportation：
235MtCO2/yr

0%

Low cost

Almost 100%
(Assumption)
63%(Optimization results)

10%

20%
Hydrogen production
such as waterelectrolysis, hydrogenliquefaction facility
cost: Halved

4. Hydrogen
Innovation

Standard
cost

Domestic storage:
91MtCO2/yr,
Overseastransportation:
235MtCO2/yr

Standard assumption(no fully autonomous
cars)

10%

Domestic: 91Mt,
Overseas: 235Mt

53%(Optimization results)

47%(Optimization results)

Domestic：
273MtCO2/yr、Overseas：282MtCO2/yr
Standard cost

6. Demand
Transformation

Fully autonomous
driving(Car ride sharing)Standard cost

3. Nuclear Power
Utilization*2

5. CCUS
Utilization

Cost of hydrogen

10%

Reference Case*1
1. Renewable
Energy 100%
(RE 100)

Ratio ofnuclear
power

21

44%
(Optimization results)
Realization and diffusionof fully autonomous
driving and expansion of
car ride sharing after
2030, and decrease inmaterial production due
to reduction of thenumber of automobiles

51%(Optimization results)* Regarding changes on the demand side, further scenario analysis that takes into account factors other than car sharing will be conducted.
*1：There is no feasible solution without DAC, and DAC is assumed to be available in all scenarios.
*2：Nuclear power utilization scenarios up to a ratio of 50% are separately examined.

【ref.】Concept of Innovation in Power Supply Ref. Value
22

Each power source must overcome a large hurdle to achieve the reference values for power sources in 2050 aspresented at the Strategic Policy Committee.
Under these conditions, for the 30 to 40% of nuclear power and fossil+CCUS, in case the upper limit of nuclear
power is 10%, it is necessary to cover 20-30% with fossill+CCUS, thus it is assumed a considerable amount of CO2
is stored at home/abroad including CCUS required amount other than the electric power sector. For hydrogen/ammonia and carbon recycled fuel, it is assumed that infrastructure development, etc. is expected to execute alarge-scale transportation without setting the upper limit of supply on the model.
It should be noted that in this analysis, the conditions were set by mechanically assuming such CCS storage
amount based on the above reference values.
2020/12/21 Strategic Policy Committee Material

Renewable Energy

・ Continue to aim for maximum introduction as the main power source in 2050.
・ Immediately work on issues to promote the maximum introduction such as adjustment amount, transmission capacity, ensuring
inertial force, responding to natural conditions and social constraints, maximizing cost control, and increasing social transformation
to cost increases.
・ How about deepening discussions on covering 50-60%(approx.) of the generated power (* 1) with renewable energy in 2050 as areference value (* 2)?

Nuclear power

・As an established decarbonized power source, aim for a certain scale of utilization on the premise of safety.
・ In order to restore public trust, make an increased effort to improve safety, gain understanding and cooperation of the locationarea, solve back-end problems, secure business feasibility, maintain human resources and technical capabilities, etc. How about
deepening discussion on covering 30-40% (approx.) with nuclear power which is a carbon-free power source other than renewableenergy and hydrogen/ammonia, along with fossil+CCUS/carbon cycle in 2050 as a reference value (* 2)?

Thermal power

Power sources required innovation

Established decarbonized
power source

In order to aim for carbon neutrality in 2050, stable power supply from decarbonized power sources is indispensable. From the perspective of 3E+S, multiple
scenarios will be analyzed without limiting to the following. In deepening the discussion, the positioning of each power source is suggested as follows.

Fossil + CCUS

・ While having the advantages of supply capacity, adjustment power, and inertial force, decarbonization of fossil-fired power is the
disadvantage.
・Aim to utilize on a certain scale iimmediately by developing technology and suitable sites, expanding applications and reducing
cost, etc., toward the implementation of CCUS / carbon recycling. How about deepening discussion on covering 30-40% (approx.)
together with nuclear power which is a carbon-free power source other than renewable energy and hydrogen/ammonia in 2050 as areference value (* 2)?

Hydrogen,Ammonia

・While having the advantages of adjusting power and inertial force without emitting carbon during combustion, the challenges are
establishing technology for large-scale power generation, reducing costs, and securing supply. Aim to build a stable supply chain
immediately by promoting co-firing of gas-/coal-fired power, increasing supply and demand.
・Aim for a certain scale of utilization as a carbon-free power source, taking into account competition with industrial andtransportation demand. Based on the fact that procurement required for future power generation is estimated to be 5-10-million ton
as basic hydrogen strategy, how about deepening discussion on covering 10% (approx.) of generated power withhydrogen/ammonia in 2050 as a reference value (* 2)?

*1: The amount of power generated in 2050 will be about 1.3-1.5 trillion kwh as a reference value (* 2) based on the power generation estimation by RITE presented at "the 33rd Strategic
Policy Committee".
*2: This is not as a government goal, this is one guideline / option for future discussions. This will be the one of options to deliberate in considering multiple scenarios in the future.

【ref.】Conditions to Realize Carbon Neutrality
in Japan by 2050

23



Under the medium socio-economic scenario SSP2 (see appendix), Direct Air Carbon
Capture and Storage (DACCS), which realizes negative emission reduction, is anecessary condition for realizing carbon neutrality in Japan in 2050. Furthermore, ouranalysis shows that hydrogen direct reduction steelmaking in the iron and steel
sector needs to be put into practical use by 2050, or the domestic CO2 storage
capacity in 2050 needs to be larger than 91 MtCO2/year that is assumed as standard.
(reported at the Green Innovation Strategy Meeting in November, 2020)



Therefore, in all the scenarios, it is assumed that DACCS and hydrogen direct
reduction steelmaking will be available by 2050.

(Source) Document from the Green Innovation Strategy Meeting (November, 2020)

Assumption for Solar PV Power Generation Costs inJapan：Time Series
Rooftop solar PV power generation

Large-scale solar PV power generation

350

350

300

屋根置太陽光（標準シナリオ）：下限
Rooftop solar
PV (Standard scenario): Lower limit

Large-scale solar
PV (Standard scenario): Lower limit
大型太陽光（標準シナリオ）：下限

Rooftop solar
PV (Standard scenario): Upper limit
屋根置太陽光（標準シナリオ）：上限

Large-scale solar
大型太陽光（標準シナリオ）：上限
PV (Standard scenario): Upper limit
300

Rooftop solar
PV (Low scenario): Lower limit
屋根置太陽光（低位シナリオ）：下限

大型太陽光（低位シナリオ）：下限
Large-scale solar
PV (Low scenario): Lower limit
大型太陽光（低位シナリオ）：上限

Rooftop solar
PV (Low scenario): Upper limit
屋根置太陽光（低位シナリオ）：上限

Large-scale solar PV (Low scenario): Upper limit

250

250

Power generation
cost[$/MWh]
発電コスト[$/MWh]Power generation
cost [$/MWh]
発電コスト[$/MWh]24

200

Cost range of rooftop
Integration costsolar PV in Standard scenario
150

Marginal cost increases
as introduction expands

Cost reduction
overtime
100

200

Integration cost

Cost range of large-scalesolar PV in Standard scenario

150

100

Cost range of rooftop solar PV
in Low cost scenario

50

Cost range of large-scalesolar PV in Low cost scenario

50

0
2010

2015

2020

2025

2030

2035

2040

2045

Assumption on integration costis given on page 30.

2050

0
2010

2015

2020

2025

2030

2035

2040

2045

2050

Cost and potential curve in 2050 is given on page 28.

*It should be noted that this is the average cost of the facility stock installed at each point in time, and is not the cost limited to new facility
installed at that point in time.
(Note) The gradation part is just an image of model calculation.

Assumption for Wind Power Generation Costs in Japan：
Time Series
Onshore wind power generation

Offshore wind power generation

350

350
Offshore wind power (Standard scenario): Lower limit

Onshore wind power (Standard scenario): Lower limit

陸上風力（標準シナリオ）：下限

洋上風力（標準シナリオ）：下限

陸上風力（標準シナリオ）：上限

陸上風力（低位シナリオ）：下限
陸上風力（低位シナリオ）：上限
Onshore wind power (Low scenario):
Lower limit300

洋上風力（低位シナリオ）：下限
洋上風力（低位シナリオ）：上限
Offshore wind power (Low scenario): Lower limit

300

Offshore wind power (Low scenario): Upper limit

Onshore wind power (Low scenario): Upper limit

250

Cost range ofoffshore wind powerin Standard scenario

標準シナリオ時
Cost rangeofの陸上コスト幅
onshore wind
power
in Standard scenario

Integration
cost
統合費用

150

Marginal cost increases
as introduction expands

発電コスト[$/MWh]Power generation
cost[$/MWh]250200

洋上風力（標準シナリオ）：上限

Offshore wind power (Standard scenario): Upper limit

Onshore wind power (Standard scenario): Upper limit

発電コスト[$/MWh]Power generation
cost [$/MWh]

25

100

Integration
cost

200

150

100

Cost reduction over time
50

50

0

0
2010

2015

2020

2025

2030

Assumption on integration costis given on page 30.

2035

2040

2045

2050

2010

2015

2020

2025

2030

2035

2040

2045

2050

Cost and potential curve in 2050 is given on page 28.

*It should be noted that this is the average cost of the facility stock installed at each point in time, and is not the cost limited to new facility
installed at that point in time.
(Note) The gradation part is just an image of model calculation.

【ref.】Assumptions for
Global Solar PV Power Generation

26

The world's total power generation
potential is estimated to beapproximately 1,270,000 TWh/yr(assuming a sufficient supply for
all potentials).

2010年* See the appendix for the cost potential of the actual model assumption(Note) It is the 2000 price. The US consumer price index (CPI) is
1.38 in 2015 when the CPI in 2000 is 1.

Distribution is
calculated fromsolar radiation
intensity data
(actually discretedata) .

Source) IRENA

Below 60$/MWh (6% of
total potential)
60 ‐ 80$/MWh (24%)
80 ‐ 100$/MWh (40%)
Over 100$/MWh (30%)

In 2050
Standard scenario
Low cost
scenario

Below 30$/MWh (15% of total potential)
30 ‐ 40$/MWh (14%)
40 ‐ 60$/MWh (30%)
Over 60$/MWh (41%)* In the DNE21 + model, it is assumed that additional costs for system stabilization will be required as the share of VRE increases.

【ref.】Changes in Solar & Wind Power Generation Costs(¥/kWh)• The cost has been
largely decreasing.
• There is a large pricedifference internationally(this motivates the useof overseas renewableenergy (blue hydrogen)).

USD/kWh

Solar power generation

27

Solar power(Japan)First half of 2020: ¥13.2¥7.7
Solar power(World)(¥/kWh)Onshore wind power(Japan)

USD/kWhWind power generation

Japan

GermanyFirst half of 2020: ¥12.9n

Onshorewind power(World)(Source) IRENAFirst half of 2020: ¥5.5

¥8.1
First half of 2020:¥4.8(Source) Advisory
Committee for
Natural Resources
and Energy

Assumption for Japan’s Variable Renewable Energy
Cost and Potential in 2050

28

800
太陽光発電(標準シナリオ)
Solar PV (Standard scenario)
太陽光発電(低位シナリオ)
Solar PV (Low scenario)

700[TWh/yr]
Power 発電ポテンシャル
generation potential[TWh/yr]Standard cost
scenario

Low cost
scenario

Onshore wind (Standard)
陸上風力発電(標準シナリオ)

600

Possibility of cost increase due to deterioration ofland conditions because of expanding installedcapacity (not fully considered in the model)

陸上風力発電(低位シナリオ)
Onshore wind (Low)
洋上風力発電(標準シナリオ)
Offshore wind (Standard)

500

洋上風力発電(低位シナリオ)
Offshore wind (Low)

Possibility of further
cost down due totechnological progress

Devastated agricultural land
(before leveling)

Devastated agricultural land
(after leveling)400
It should be noted that cost increases due to worsening land conditions, such as land
preparation costs for devastated agricultural land, are not fully incorporated.
The condition is that various restrictions are resolved.

300

1. Promotion of location in the protection forest area
(Relaxation of designation cancellation requirements,etc.)
2. Elimination of location restrictions in natural parks(Reexamination of area designation)
3.Promotion of location in the green corridor
4.Promotion of location in abandoned cultivated land anddegraded agricultural land (relaxation of agricultural
promotion exclusion requirements)

200
Continued effort in 2030：110 TWh/yr

100

Strengthening policy in 2030: 29 TWh/yr

0
0

50

100

150

Strengthening policy in 2030: 10 TWh/yr
200
250[$/MWh]Power発電コスト
generation
cost [$/MWh]*Cost and potential of solar PV power generation is estimated by RITE based on the GIS data for the amount of solar radiation andland use, and facility costs, etc. Both rooftop and large-scale solar power generation are included in this Figure. Cost and potential ofonshore wind power generation is estimated by RITE based on the GIS data for wind conditions and land use, and facility costs, etc.

Assumptions for Estimating Integration Costin the Univ. Tokyo - IEEJ Model
Regional aggregation
Divide Japan into 5 regions（[1] Hokkaido,[2] Northeastern area, [3] Tokyo, [4] Westernarea other than Kyushu, [5] Kyushu）

29

Expected cost reduction of Lithium-ion
battery (NREL)

Target time period
Assuming costs and electricity supply
and demand in 2050
Power generation costs for each powersource Based on assumption in RITEDNE21+ modelPower storage system(Source) W. Cole and A. W. Frazier, “Cost projections forutility-scale battery storage: 2020 update,” NREL/TP-6A2075385.

Mainly with Lithium-ion battery (setting 150$/kWh in 2050 based on estimation by the National
Renewable Energy Laboratory (NREL)), it is assumed that existing pumped-storagehydropower and hydrogen storage will be used together.

Cost of interconnection lines
With reference to the plan by the Organization for Cross-regional Coordination ofTransmission Operators, costs of interconnection lines are assumed to be ¥200,000/kW
between areas [1] [2] and [3][4], and ¥30,000/kW in other areas, with an annual expense
ratio of 8%. Underground transmission lines and submarine cables between Hokkaido andTokyo are not considered.

Assumption for Integration Costs
for Grid Measures (in 2050)

30

Grid integration costs approximated from the analysis of the Univ. of Tokyo – IEEJ
power generation mix model＝Assumption on grid integration costs in DNE21+(Marginal cost when each implementation share is realized）* The total cost is calculated as an integral value.

700

77

As the VRE ratio increases, marginal
integration costs tend to rise relatively
rapidly.
This is because under thecircumstance where a large amount of VRE
has already been installed, if it is further
installed, it will be required to maintain an
infrequently used power storage system ortransmission line to deal with the risk thatcloudy weather and windless conditions willcontinue for several days or more.

66

600

55

500

44

33

22

[US$/MWh]
System系統統合費用
integration cost
[US$/MWh][¥/kWh]Solar PV
太陽光

風力
Wind

400

*According to the IEEJ model analysis
results, the integration cost differs dependingon the combination of wind power and solar
power installed shares. In the DNE21+
model, first of all, we approximately assume
a function based only on the share of wind
power and solar power, respectively, using
integration costs of the combination of theshare of wind power and solar power derived
from the IEEJ model. Then, the difference
value is calculated for each share, and thelimited value of the integration costs for eachshare is estimated and incorporated into the
DNE21+ model.

300

200

11

100

0

0
0

5

10

15

20

25

30

35

40

Share
of total power generation[%](%)
総発電電力量に対するシェア

45

50

55

60

(Note) The potential of each VRE is as
described in the previous slide. As the sharedescribed in this Figure is limited by theassumed potential, it may not be feasible.

Assumption for Nuclear Power Generation Cost
31

Facility cost ($/kW)
Year

Power generation unit price($/MWh)Year 2000 priceYear 2018 priceYear 2000 price Year 2018 price

2020

2763

4029

75

110

2030

2779

4053

76

111

2050

2794

4075

78

114

2100

2824

4117

79

115

*1 The figures in the table are assumed values for Japan. For the rest of the world, location factors are
multiplied, resulting in slightly different assumptions.
*2 Since the base year of the model is 2000, the 2000 price is also shown; the conversion from the 2000
price to the 2018 price is multiplied by 1.46 (based on CPI of U.S.).
*3 The conversion to cost per unit of electricity generated is based on a capacity factor of 85%.

【Ref.】Projected Cost of Nuclear Power Generation
by IEA/NEA

32

New installation prices in OECD

countries have been extremely highin recent years, exceeding thecurrent model assumptions, but are
expected to decrease in the future.

(Source) IEA/NEA, Projected
Costs of Generating Electricity
2020

Assumption for CO2 Capture Technology

33

Capital costs (price in 2000)($/kW)

Generating efficiency(LHV%)

CO2 recovery rate(%)

IGCC/IGFC with CO2 Capture*1

2800 – 2050

34.0 – 58.2

90 – 99

Natural gas oxy-fuel power*1

1900 – 1400
Capital costs (price in 2000)(1000$/(tCO2/hr))

40.7 – 53.3
Required power(MWh/tCO2)

90 - 99
CO2 recovery rate(%)

851 – 749

0.308 – 0.154901309 – 1164

0.396 – 0.333

90

Post-combustion CO2 capture
from biomass-fired power plant*1

1964 – 1728

0.809 – 0.415

90

CO2 capture from gasification*1

62

0.218

90 – 95

CO2 capture from steelworks
blast furnace gas*1

386 - 319

0.171 – 0.150

90

Post-combustion CO2 capture
from coal-fired power plants*1
Post-combustion CO2 capture
from natural gas-fired power
plants*1

Capital costs (price in 2000)(1000$/(tCO2/hr))
CO2 capture from clinker
manufacturing*22485 - 2246

Required fuel (GJ/tCO2)
Recovered power(MWh/tCO2)
4.87 – 3.66
0.199 – 0.150

CO2 recovery rate(%)
90

*1 The range of values in the table indicates improvement from 2015 to 2100.
*2 It is assumed that the assumed values have a range shown in the table depending on the fuel type used in the kiln body, CO2 capture, andcompression equipment.
Note) It is 2000 price. The US consumer price index (CPI) in 2018 is 1.46 when the CPI in 2000 is 1.
Not only the CO2 capture technologies in the power sector, but also CO2 capture from gasification (during hydrogen production) and CO2
capture from steelworks blast furnace gas and from clinker manufacturing are explicitly modeled.

Assumption for CO2 Transportation and Storage
CO2 storage potentials (GtCO2)
Depl. oil well (EOR)

Japan

World

0.0

112.4

【References】
IPCC SRCCS (2005)(GtCO2)34

Storage costs($/tCO2)*1
92 – 227*2

675–900
Depl. gas well0.0

147.3 – 241.5

10 – 32

Deep saline aquifer

11.3

3140.1

103–104

5 – 85

Coalbed (ECBMR)

0.0

148.2

3–200

47 – 274*2

Note 1: It is assumed that the CO2 storage potentials of depl. gas well could be expanded to the upper limit in the table with the increase of future mining volume.
Note 2: It is assumed that the storage costs could rise within the range in the table with the increase of accumulated storage amount.
*1 The costs for CO2 capture are not included. They are assumed separately.
*2 Oil and gas profits from enhanced oil recovery and enhanced methane recovery are not included in this figure, but they are assumed separately.

The constraint on CO2 storage expansion is assumed considering the difficulties of its rapid
expansion, e.g. limited number of drilling rigs; storage can be expanded by 0.02%/yr until 2030 andafterwards by 0.04%/yr for domestic/regional total storage implementation in the baseline scenario.
(The maximum storage potential in 2050 is 91MtCO2/yr in Japan’s case, where CCS is assumed to beavailable after 2030.)
 It can be expanded up to 3 times (273 MtCO2/yr) that in CCUS innovation scenario. (Total storage
potential is fixed.)
CO2 transportation cost
 CO2 transportation costs from the sources to the reservoirs are assumed separately as 1.36$/tCO2(per 100km) and 300km for average transport distance in Japan’s case.
 For large area countries which are disaggregated in the models (US, Russia, China and Australia),
the interregional CO2 transportation costs are estimated according to the transportation distance.
 Cross-border CO2 transportation is also assumed. In CCUS standard scenario, such as Reference
value case, the upper limit of export from Japan is 235 MtCO2 (equivalent to one-sixth of 2013 GHG
emissions). (In CCUS utilization scenario, it is 282 MtCO2 (equivalent to one-fifth of 2013 emissions)).
Assumption for Hydrogen Production andTransport-Related Technologies

35

Hydrogen production technologies
Facility cost (US$/(toe/yr))

Conversion efficiency (%)

Coal gasification

1188 - 752

60%

Gas reforming

963 - 733

70%

Biomass gasification

1188 - 752

60%

Water electrolysis

2050 - 667

64 - 84%

Facility cost (US$/(toe/yr))

Electricity consumption (MWh/toe)Natural gas/Synthetic methane

226

0.36

Hydrogen

1563

1.98

Liquefaction technology

Transport cost
Facility cost

Variable cost*1

Electricity: $/kW
Other energy: US$/(toe/yr)
CO2：US$/(tCO2/yr)

Energy: US$/toe
CO2: US$/tCO2

283.3+1066.7L-

Pipeline*3

210.0L

5.0L

Tanker

69.5L

7.26+0.60L

Pipeline*3

99.4L

2.35L

Tanker

47.5L

1.77L

Pipeline*2

128.3L

3.5L

Tanker

35.1L

8.09+0.39L

Electricity*2
Hydrogen

CO2
Natural gas(The same applies tosynthetic methane.)

L: Distance between regions (1000km)*1 For ships, the distance-independent term assumes fuel costs. For pipelines, the distance-dependent terms assume fuel costs and compression power costs, respectively.
*2 For submarine transmission lines, fixed costs are assumed to be 10 times higher than the above.
*3 For submarine pipelines, fixed costs are assumed to be three times higher than above.

Assumption for Shared Mobility Induced
by Fully Autonomous Cars

36

 In the case where demand decreases through car-sharing, fully autonomous sharedcars can be available after 2030, and key parameters are assumed as below, mainly
following Fulton et al. (2017).
200

Increase in annual distance traveled
per vehicle due to car-sharing [%]Increase in number of passengers
per vehicle [%]Assumption for car-sharing

Assumption for ride-sharing

40
35
30
25
20
15
10
5

150

100

50

0

0
0

1500
3000
4500
6000
7500
9000
Passenger car travel service per area [thousand p-km/km2]

Items
Car body price0

Traditional car (private car)

200

400

600

800

Population density [person/km2]

Fully autonomous car (shared car)

Assumed precisely dependingon car types

2030: +10000$
2050: +5000$
2100: +2800$(compared to traditional cars)
Lifespan of car
13-20 years
4-19 years
Number of passengers per
2050: 1.1-1.5 passengers
2050: 1.17-2.06 passengers
vehicle2100: 1.1-1.3 passengers
2100: 1.11-1.89 passengers
 Opportunity costs of time required for driving and costs related to safety are considered.
 Impacts of the reduction in the number of cars induced by car- & ride-sharing are considered.

Following impacts driven by decrease in the number of cars are considered: 1. decrease in steel
products and plastic products, 2. decrease in concrete and steel products due to the decrease in multistorey car park space.

In our assumption, the actual natural and social constraints are not precisely incorporated as cost and upper bound constraints. If these factors aretaken into consideration more precisely, there is a possibility that the cost will increase / decrease further depending on the power source.
Reference Case in 2050
Assumption

Description

Integration
cost
Upper
limit
Price
Price

Upper
limit

About ¥13/kWh

Price
Upper
limit

Fossil ＋ CCS

About ¥4/kWh(Integration cost for solar andwind power by IEEJ model
analysis)

PV: about 750 billion
kWh
WT: about 300 billion
kWh

Upper
limit

Hydrogen

Nuclear power

Renewable energy

Price

Capital cost
PV: about ¥10-17/kWh
WT: about ¥11-20/kWh(2018 price conversion)

10%Power generation: About¥16-27/kWh
Hydrogen: About ¥2545/Nm3

None
Power generation
Coal-fired: About ¥13/kWh
Gas-fired: About ¥16/kWhCCS
Coal-fired: About¥7400/tCO2
Gas-fired: About¥10,000/tCO2

Innovation Case in 2050

O&M cost

Based on Working Group for Power Generation Costs(Assuming decrease in facility such as panels, as well as
construction and land development)

Capacity factor

Based on GIS data (solar radiation, wind conditions), consistent
with the world

Battery cost

About ¥15,000/kWh
Cost projection by NREL

Grid expansion
cost

Based on documents by such as OCCTO

Upper limit

Based on GIS solar radiation, wind speed data and land use data

Capital cost
O&M cost

Facility cost 4075$/kW
Assumed with reference to cost report by NEA and Power
Generation Cost WG

Capacity factor

Upper limit 85%

Upper limit

Assuming 60-year operation of some existing furnaces

Capital,O&M cost

Facility cost 1160$/kW(Assuming 60$/kW is added as high-efficiency gas CC facility cost
+ NOx countermeasure cost)

Assumption
Capital cost
PV: about ¥6-10/kWh
WT: about ¥8-15/kWh

About ¥4/kWh(Integration cost for solar andwind power by IEEJ model
analysis)

PV: about 750 billion
kWh
WT: about 300 billion
kWh(2018 price conversion)

20%

Power generation: about¥13-21/kWh
Hydrogen: about ¥20-35/Nm3

Calculated in the model

Capacity factor

Calculated in the model with upper limit 85%

Upper limit

No upper limit on import volume

None

Facility cost 1100-1700$/kW

Power generation
Coal-fired: About ¥13/kWh
Gas-fired: About ¥16/kWhCCS
Coal-fired: About¥7400/tCO2
Gas-fired: About¥10,000/tCO2

Capital, O&M
and fuel cost

O&M cost

Assumed with reference to future projection by IRENA,
WEO, etc.

Capacity factor

Based on GIS data (solar radiation, wind conditions),
consistent with the world

Battery cost

About ¥15,000/kWh
Cost projection by NREL

Grid expansion
cost

Based on documents by such as OCCTO

Upper limit

Based on GIS solar radiation, wind speed data and landuse data

Capital cost
About ¥13/kWh

Fuel cost(High-efficiency coal power generation: 1700$/kW, high-efficiency
gas CC power generation: 1100$/kW, when including CO2
recovery facility cost (actually, the recovery facility capacity(installation ratio) is calculated in the model), about 2100 $/kW
and about 1450$/kW, respectively)(With reference to NEA report and Power Generation Cost WG)

Description

O&M cost

Facility cost 4075$/kW
Assumed with reference to cost report by NEA andPower Generation Cost WG

Capacity factor

Upper limit 85%

Upper limit

Assuming that new expansion and replacement will be
realized by restoring public confidence, etc.

Capital,O&M cost

Same as Standard Case

Fuel cost

Further reduction of manufacturing costs overseas andrealization of very low-cost freight technology

Capacity factor

Calculated in the model with upper limit 85%

Upper limit

No upper limit on import volume

Capital, O&M
and fuel cost

Same as Standard Case

CCS price

Based on various documents

Calculated in the model with upper limit 85%

CCS price

Based on various documents

Note: Assuming cost curve forCO2 storage cost that depends
on how much CCS is
conducted

Capacity factor

Calculated in the model with upper limit 85%

Note: Assuming cost curve forCO2 storage cost that
depends on how much CCS is
conducted

Capacity factor

Domestic: 90 million
tCO2/year
Overseas: 230 million
tCO2/year

Upper limit

Assuming storage potential based on GIS data in Japan,
considering rig restrictions, etc., and assuming restrictions on the
procurement amount of transport vessels overseas

Domestic: 270 million
tCO2/year
Overseas: 280 million
tCO2/year

Upper limit

Assuming that the amount of storage will
increase domestically by overcoming the
restrictions on drilling rigs.
37

４．Results of Scenario Analysis

Total Primary Energy Supply in Japan in 2050
39
450

Primary energy supply [Mtoe/yr]

Gas: non-energy use
400

Oil: non-energy use

350

Import: Hydrogen andammonia
Import: Biofuel

300

Solar thermal
Solar PV

250

Wind power
Nuclear power

200

Hydro and Geothermal
150

Biomass w/CCS
Biomass w/o CCS

100

Synthetic methane
50

Gas w/CCS
Gas w/o CCS

2015

6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE100

Referencecase

0Synthetic oil
Oil w/o CCS
Coal w/CCS
Coal w/o CCS

2050

Note 1) Conversion rates of primary energies correspond to IEA statistics.
Renewable energies except biomass : 1 TWh = 0.086 Mtoe, nuclear : 1TWh = 0.086 / 0.33 Mtoe
Note 2) Fossil fuels without CCS are offset with NETs, thus serving as carbon-neutral fossil fuels.

All are offset with NETs
in ▲100% scenarios

 Substantial amount of imports of hydrogen, ammonia and synthetic fuels are observed in allof ▲100% scenarios.

Electricity Supply in Japan in 2050
40
1600

Solar PV w/o gridWind power w/o grid

1400

Coal and hydrogen orammonia
Hydrogen and ammonia

1200

Solar PV

1000

Wind power
Nuclear power

800

Hydro and geothermal

600

Coal and biomass w/ CO2
captureBiomass w/ CO2 capture

400

Coal and biomass w/o CO2
captureBiomass w/o CO2 capture200

Gas w/ CO2 capture
Gas CGS02015

6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE100

Gas w/o CO2 capture

ReferencecaseElectricity [TWh/yr]

Solar thermal

Oil w/ CO2 capture
Oil w/o CO2 capture
Coal w/ CO2 capture
Coal w/o CO2 capture2050

 Increases in integration costs are observed in the case where renewable energy share ishigher than that in the Reference case. Especially for the RE100 case, a surge in integration
costs significantly raises marginal cost of electricity supply, causing considerable decreasein electricity demand. An increase in BECCS instead of fossil fuel + CCS is observed forsupply-demand balance.

【ref.】 Electricity Generation Share in 2050
41
100
90

2
23

25

23

20

Fossil fuel+CCUS

35

80
70

13

60

10

2

4
23

10
20

50

15
10

10
97

10

Hydrogen andammonia

1040
Nuclear power
30

63
54

53

20

47

44

51

10

Renewable energy

6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE1000ReferencecaseElectricity generation share [%]

24

2050

 Modifying assumption of power generation by each scenario and consequent changes inelectricity generation share from the Reference case would cause a decrease in share of
expensive power generation. Under assumption of this analysis, hydrogen generation is
likely to decline, and assuming further cost reduction of hydrogen or a higher cost for otherelectricity would cause a decrease in other power generation.

Final Energy Consumption in 2050
42350
Gaseous fuel: natural gas(non-energy use)

Final energy consumption [Mtoe/yr]

300

Liquid fuel: oil (non-energyuse)Electricity

250

Gaseous fuel: hydrogen
200
Gaseous fuel: syn. Methane
150

Gaseous fuel: natural gas
Liquid fuel: biofuel

100

Liquid fuel: syn. Oil
50
Liquid fuel: oil

2015

6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE100

Referencecase

0

Solid fuel: biomass
Solid fuel: coal

All are offset with NETs
in ▲100% scenarios

2050

Note: Fossil fuels without CCS are offset with NETs, thus serving as carbon-neutral fossil fuels. A shift from coal to gas is observed in
sectors such as industry, and gas is likely to remain used in sectors where electrification is difficult.

 Significant reduction of energy consumption is seen in 2050 for every scenario of ▲100%.
 Increases in integration costs are observed in the case where renewable energy share is higher thanthat in the Reference case. Especially for the RE100 case, a surge in integration costs significantly
raises marginal cost of electricity supply, causing considerable decrease in electricity demand.
Electrification is slow in sectors such as Residential and Commercial, and thus oil demand is higher
compared to the Reference case.

【ref.】 Final Energy Consumption Share in 2050
43100

Gaseous fuel: naturalgas (non-energy use)

90

Liquid fuel: oil (nonenergy use)
Electricity

70

Gaseous fuel:hydrogen30

Liquid fuel: syn. Oil

20

Liquid fuel: oil

10

Solid fuel: biomass

0

Solid fuel: coal
6. Demand
Transformation

Liquid fuel: biofuel

5. CCUS
Utilization

40

4. Hydrogen
Innovation

Gaseous fuel: naturalgas

3. Nuclear
EnergyUtilization

50

2. RE
innovation

Gaseous fuel: syn.
Methane1. RE10060

Referencecase

Final energy consumption [%]80 Electrification rate increases significantly to about 40% in all scenarios except RE100, fromcurrent level of about 20%.
 Fossil fuels with using existing assets and DACCS, or fuels from captured carbon such assynthetic oil or synthetic methane are utilized.

CO2 Balances in Japan in 2050
44

CaptureCapture

500

400

DAC
Ammonia production
Cement200

BF-BOF
Hydrogen production

100

Biomass-fired0

Gas-firedOil-fired-100

Coal-fired-200

Storage, utilization
CO2 geological storage

-300

CCU
-400

Overseas transport
6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE100-500

Referencecase

CO2 capture, storage and utilization [MtCO2/yr]

300

Storage,utilization

2050

 In the RE100 case, fossil fuels + CCS is excluded and BECCS is utilized instead.

GHG Emissions by Sector in Japan in 2050
45
1400
DACCS
1200

Non-CO2 GHG
Process CO2

1000

800

Other energy conversion
Power generation

600

Residential & Commercial
400

Other domestictransportation
Domestic aviation

200

Road transportation
0

Other industry
Chemical-200

Pulp & Paper

2015

2050

6. Demand
Transformation

5. CCUS
Utilization

4. Hydrogen
Innovation

3. Nuclear Energy
Utilization

2. RE innovation

1. RE100-400
Referencecase

GHG emieeions [MtCO2eq/yr]

LULUCF CO2CementIron & Steel【ref.】 Marginal Costs of Electricity
Electricity generation cost [$/kWh]46* Cost curve is illustrated as an image andis complex actually

Integration costs

Marginal costs
Renewableof generation
Hydrogen andenergyammonia
Thermal powerwith CCS

Demand curve(including demand for energy
conversion of non-electricity)


Hydro
power

NuclearpowerLong-term marginal costs of electricity
including facility costs (marginal costs
are equivalent to annual average costs,
although varying by time of the day)T&D costs are not included, except for
integration cost (for example, prices forlow voltage power supply need toconsider additional 10 JPY/kWh as T&D
costs (wheeling fee))

Electricity generation [TWh]* Hydropower, nuclear power and CCS are constrained by their quantity
before reaching their marginal costs【ref.】 Differences inretail prices of electricity
in EU scenarios(increases in priceevidently shown)
Source) IN-DEPTH ANALYSIS IN SUPPORT OF THE
COMMISSION COMMUNICATION COM (2018)

1.5TECH: +84 Euro/MWhSummary (preliminary)47

 It is noted that scenario assumptions for this analysis such as introduction amount or costs of technology options do not take into accountnatural or societal constraints in Japan in detail, as well as that costs are assumed on the basis of cost projections by internationalorganizations and the like. Future landscape that aligns more with realities can be drawn with further analysis considering these
constraints precisely.
 Therefore, it is crucial to constantly consider various constraints not evident in figures below, instead of utilizing only appearances of those
figures for future policymaking.
 Moreover, marginal cost of electricity, namely electricity cost (electricity costs at output, and additional wheeling fee of about 10 JPY/kWhrequired for retail prices. Hereafter referred to as “electricity cost”) , is approximately twice as high as calculated price for the year 2020
(approx. 13 JPY/kWh), even for the Reference case. Reduction of those costs would be essential towards carbon neutrality by 2050, fromthe perspective of industrial competitiveness.
 For the assumed required amount of hydrogen and ammonia outside the power sector and CCUS in the Reference case, realization ofsignificant amount of hydrogen and ammonia supply or CO2 storage both domestically and abroad is mechanically assumed for drawing avision of reference value, on the basis that barriers such as assuring appropriate sites or infrastructure development are to be overcome.
 All cases in this analysis, including the Reference case, utilization of carbon removal technologies such as H2-based direct reduced iron in
non-power sector or DACCS is assumed (CO2 storage capacity of CCUS in this analysis considers CO2 also from non-power sector).
Totalelectricity
generation

Power generation mix
Renewableenergies

Nuclear
power

Hydrogen,Ammonia

CCUSThermal

Reference case
* Case withassumptions forrealizing a vision ofreference value
towards carbon
neutrality in 2050
indicated at thecommittee

Renewable Energy
100%
11,350 TWh

1,050
TWh

54%
(730)

Approx.
100%

10%
(140)

0%

13%
(180)

0%

Implications of analysis results,
Challenges to achieve results

23%
(310)

 All power generations are required to overcome all of technical, natural or
societal, and economic challenges. This scenario is constructed under
the assumption that these various challenges are to be overcome. Hardto-achieve level for each power generation.
 Assumed level of generation costs per kWh for inputs are ¥10 - 17 forsolar PV, ¥11 - 20 for wind, ¥13 for nuclear, ¥16 - 27 for hydrogen andammonia, and ¥13 - 16 for CCUS-thermal. Electricity cost (marginal costsof electricity) is ¥24.9 per kWh, which does not consider natural andsocietal constraints in detail. Assumed potentials for CO2 storage are 91
MtCO2/yr for Japan and 230 MtCO2/yr for export.

0% A scenario where renewable energy share is exogenously assumed as
100%. Electricity costs for inputs are assumed as same with theReference case.
 Electricity cost is ¥53.4/kWh due to an increase in system integration
costs. As a result of unavailability of other low cost power options,electricity consumption would be reduced.
 Moreover, significant level of challenges such as natural and societal
constraints are required to be overcome for realizing such amount of
renewable energy introduction which might not be realistic.

Summary (preliminary)48
Cases with modified
assumption of theReference case due totechnologicalinnovation assumption↓

Renewable
Energy Innovation
2

Nuclear Power
Utilization
3

Hydrogeninnovation
4

Power generation mix
Totalelectricity
generation

1,500
TWh

1,350
TWh

1,350
TWh

Renewableenergies

63%
(950)

53%
(720)

47%
(630)

Nuclear
power

10%
(150)

20%
(270)

10%
(140)

Hydrogen,ammonia

2%
(30)

4%
(50)

23%
(310)

CCUSthermal

Implications of analysis results,
Challenges to achieve results

25%
(380)

 More innovation is realized in renewable energy compared with the Reference
case, such as development and commercialization of new solar PV or windturbine with higher generation efficiency, which induce significant reduction inassumed generation costs; ¥6 – 10/kWh for PV and ¥8 - 15/kWh for wind.
 More introduction is required compared with the Reference case, with naturaland societal constraints overcome.
 Renewable energy cost is lower than hydrogen, therefore are introduced inprior to hydrogen in this scenario. Electricity cost in this scenario is ¥22.4/kWh.

23%
(310)

 A scenario with the assumption that nuclear power would consists of power
generation mix with upper limit of 20%, assuming that replacement or new
construction of nuclear power plant are realized based on advanced public
understanding for nuclear power compared with the Reference case.
 Electricity cost in this scenario is ¥24.1/kWh.
 Electricity cost with hypothetically setting upper limit for nuclear power at 50%
is ¥19.5/kWh.

20%
(270)

 Assumed generation cost of hydrogen is ¥13 – 21/kWh, based on significant
hydrogen cost reduction is realized through technological innovation relating tohydrogen production (facility costs of water electrolysis or hydrogenliquefaction) as well as market expansion with increased private investment,
compared to the Reference case. Electricity cost in this case is ¥23.5/kWh.
 Additional hydrogen supply infrastructure is required in a similar scale assumed
in the Reference case.

CCUS Utilization
5

1,350
TWh

44%
(590)

10%
(140)

10%
(140)

35%
(470)

 Storage potential for CO2 is assumed to expand significantly (270 MtCO2 forJapan and 280 MtCO2 for export) compared to the Reference case, with further
technological innovation. Electricity cost in this case is ¥22.7/kWh.
 Required storage potential of CO2 in Japan would almost triple of that in the
Reference case.

Demandtransformation
6

1,350
TWh

51%
(690)

10%
(140)

15%
(200)

24%
(320)

 Realization and diffusion of fully autonomous vehicles, and substantial diffusionof car sharing and ride sharing are assumed.
 Other assumptions are same as those in the Reference case. Electricity cost in
this case is ¥24.6/kWh.

*Regarding demand side transformation, further scenario analysis considering factors other than car sharing would be conducted.

Implications of Scenario Analysis Results
49The scenario analysis provides implications below.
• For non-power sectors, technologies for removal or recycle of carbon such as H2-based direct reduced iron or DACCS are
imperative. Without implementing these technologies, an achievement of carbon neutral society is extremely difficult.
• In light of technological difficulties in decarbonizing non-power sectors, decarbonization of the power sector, which alreadyhas established decarbonizing technologies, is prerequisite for achieving carbon neutrality by 2050. While each power
generation has various challenges and constraints, preconditions to overcome these challenges and constraints forrealizing the reference value are considered and assumed for the Reference case. In addition to substantial difficulties inovercoming these challenges and constraints, electricity cost is projected to be twice as high as current one, and all ofthese challenges are required to be overcome.
• For a model analysis, it is possible to exogenously assume further increased level of introduction of renewable energy
which would cause increases in generation costs or system integration costs as they are introduced, but in reality,
increasing dependence on such power generation to an extremely high level is difficult due to natural condition or societal
constraints. Moreover, assuming renewable energy 100%, significant increase in cost is evidently shown in the case 1.
Those results suggest that renewable energy 100% scenario might not be a realistic one.
• By comparing results for 4 cases (cases 2 to 5) where advanced technology innovation is assumed, several pathways
toward carbon neutrality by 2050 are shown to be drawn, indicating higher feasibility of carbon neutrality, if challenges ofeach decarbonized power are to be overcome with technology innovation, cost reduction, enhanced public understandings,
and alleviation of deployment constraints, as well as their deployment is further expanded. However, overcoming thesechallenges bear a lot of uncertainty yet.

=> Based on these implications, realization of various technology innovation is essential to ensure carbon neutrality into the future.
Considering uncertainty in innovation, it is important for sectors, such as the power sector where robust decarbonization isrequired, to utilize established decarbonizing technologies including renewable energy and nuclear power. Furthermore, broader
policy responses are required for securing continuous availability of these decarbonizing technologies, without narrowing policy
options.
=> Considering difficulties in foreseeing categories where innovation is realized, policy responses toward practical realization of
innovation in every category including hydrogen, ammonia and CCUS are required, without leaning to specific ones.

Appendix

Overview of Shared Socioeconomic Pathways (SSPs)
Fossil fuel price: low;
Fossil fuel resources: highTech. improve: low;
Population: high;GDP: low

Governance:lowTech. improve：high;Public acceptance oflarge-scale tech.: low;
Population: low; GDP: highPrice distributionof fossil fuelenergy prices: big

In response to a call from IPCC, the international research community on climate issues developed SSPs (Shared
Socioeconomic Pathways) for consistent analysis and evaluation on mitigation, impacts and adaptation of climatechange considering social and economic uncertainties, as well as for aggregation of scientific knowledge, based on
which quantitative analyses with Integrated Assessment Models are being conducted.
RITE has been conducting evaluation on energy and climate policies under several SSPs with using the Integrated
Assessment Model DNE21+. For this study, only SSP2 scenario is analyzed due to time constraints.

51

Assumed Socioeconomic Scenarios

52

Shared Socioeconomic Pathways, SSP1 to 5, are developed in response to a call from IPCC.
Among the quantitative scenarios developed by RITE in line with these SSPs storylines, thisstudy assumes SSP2 “middle of the road” scenario to deliver the analyses.

【World】
2030

2050

2100

Population (billion people)

8.36 (8.14-8.59)

9.21 (8.61-10.05)

9.31 (7.00-12.73)

GDP (%/year)

2.7 (2.4-3.1) [2010-]

2.2 (1.3-2.8) [2030-]

1.4 (0.6-2.2) [2050-]

Crude steel production (billion ton)

1.96 (1.88-2.00)

2.13 (1.93-2.27)

2.29 (1.47-2.65)

Cement production (billion ton)

4.16 (3.90-4.30)

4.40 (3.85-4.66)

4.47 (2.94-5.91)

Passenger transport demandin Road sector (trillion p-km)

30.2 (31.2-37.3)

60.0 (56.8-74.2)

83.3 (66.8-88.8)

2030

2050

2100

Population (billion people)

0.118 (0.116-0.126)

0.102 (0.096-0.122)

0.084 (0.047-0.105)

GDP (%/year)

1.6 (1.3-1.9) [2010-]

0.4 (-0.1-1.2) [2030-]

0.4 (-0.9-1.5) [2050-]

Crude steel production (billion ton)

0.09 (0.081-0.097)

0.095 (0.073-0.111)

0.085 (0.045-0.090)

Cement production (billion ton)

0.054 (0.050-0.068)

0.044 (0.031-0.075)

0.040 (0.023-0.065)

Passenger transport demandin Road sector (trillion p-km)

0.77 (0.69-0.85)

0.64 (0.61-0.82)

0.61 (0.51-0.70)【Japan】

Note: The values in parentheses show the scenario ranges among SSP1-SSP5. Energy demands and electricity generation are
endogenously calculated in the model.

Crude Steel Production Scenario for Global and Japan(billion ton crude-steel/yr)
0.14

53

Japan

0.12
0.1
0.08

0.090

0.095 0.095 0.092
0.093
0.091

SSP2

0.086 0.085

0.083

0.06

Global0.04

2.5
Latin America

0
2000

2020

2040

2060

2080

2100

SSP2-based scenario

Crude steel production (billion t/yr)

scenario
0.02

historical
2.0

2.3

2.1

1.9

Sab-Sahara
Middle East, North Africa Africa
Former USSR, non-OECD Europe
Asian developing countries

0.51 billion t in 2060
(1.65 billion people)

1.5

8.5

0.5

0.54 billion t(1.6 billion people)

1.06 billion t(1.4 billion people)

1.0

India

China

0.55 billion t(1.2 billion people)

OECD Asia-Pacific
OECD North America
OECD Europe

0.0
1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100

Global EAF Crude Steel Scenario

54

EAF: Electric arc furnace

Scrap-based EAF crude steel scenario

Estimated old scrap usage

2.0

2.5

Crude steel production

Estimated old scrap usage

Crude steel production, old scrap usage(billion t/yr)

Crude steel production, old scrap usage(billion t/yr)

Crude steel production

1.5

1.0

0.5

2.0

1.5

Scrap‐based EAF(Upper constraint)

BF‐BOF andDRI‐EAF

1.0

Scrap‐based EAF(Lower constraint)

0.5

0.0

0.0
1925

1950

1975

2000

2025

2000

2025

2050

2075

2100

SSP2-based scenarios

Supplementary remarks: Usage of old scrap, which is the main source of iron for scrap-based EAF, has risen slowly in thepast. In the future, the amount of old scrap usage is expected to rise gradually due to the increase in the steel stock. We
assumed upper and lower bounds on future production of scrap-based EAF steel.
Note: It is noted that expanded usage of EAF, one of the measures for low-carbon or decarbonization, has a large
constraint in an amount of old scrap available as well its quality. New technologies such as H2-based direct reduced iron
(DRI) is required for decarbonizing crude steel.

Fossil Fuel Price Scenario (Oil)180- 2050Comparison withother literature

Historical
SSP1 high level scenario

160

SSP2 medium scenario
140
SSP5 low level scenario
EIA IEO2016 high level

120

EIA IEO2016 medium

100

EIA IEO2016 low level80

WEO2015 current policy
WEO2015 new policy

60

WEO2015 low oil price40

WEO2014 current policy
WEO2014 new policy

20

WEO2013 current policy
0
2000

2010

2020

2030

2040

WEO2013 new policy

2050- 2100

160
140
120

US2000$/bbl (real)

US2000$/bbl (real)

55

100
Historical
SSP1 high level scenario

80

SSP2 medium scenario
60

SSP5 low level scenario

40
20
0
2000

2020

2040

2060

2080

2100

Fossil Fuel Price Scenario (Coal)
100- 2050Comparison withother literature

Historical
SSP1 high level scenario
SSP2 medium scenario
SSP5 low level scenario
60

WEO2015 current policy
WEO2015 new policy
WEO2015 low oil price40

WEO2014 current policy
WEO2014 new policy

20

WEO2013 current policy
WEO2013 new policy
0
2000

2010

2020

2030

2040

2050

- 2100120

100

US2000$/ton (real)

US2000$/ton (real)

80

56

80
Historical
SSP1 high level scenario

60

SSP2 medium scenario
SSP5 low level scenario

40

20

0
2000

2020

2040

2060

2080

2100

Fossil Fuel Price Scenario (Gas)US

8

US2000$/Mbtu (real)

US2000$/Mbtu (real)

10

6
5
4
3
2

8
6
4
2

1
0
2000

Europe

12

7

57

2010

2020

2030

2040

0
2000

2050

Asia (incl. Japan)

2010

2020

2030

2040

2050

Asia (incl. Japan); - 2100

14

12

Historical

16

SSP1 high level scenario

14

US2000$/Mbtu (real)10

SSP5 low level scenario
WEO2015 current policy

8

WEO2015 new policy
6

WEO2015 low oil price
WEO2014 current policy

4US2000$/Mbtu (real)

SSP2 medium scenario

12
10
8
6
4

WEO2014 new policy
WEO2013 current policy

2

WEO2013 new policy
0
2000

2010

2020

2030

2040

2050

2
0
2000

2020

2040

2060

2080

2100

Cost Modeling58【 Types of Accumulated Technology Cost】［Facility Cost］／［Payback Period］＋［Operation ▪ Maintenance Cost］＋［Annual
Fuel Cost］
Note１）▪ [Annual Expense Ratio] ≡ 1 / [Payback Period] + [Ratio of Ops. ・ Maint. Cost for Facility
Cost]* Assumption: [Annual Expense Ratio] is per technology; [Ratio of Ops. ・ Maint. Cost] is acoefficient against Facility Cost (Approx. 1-8% per yr depending on the facility)▪[Payback Period] = 1 / ([Implicit Discount Rate] / (1- (1 + [Implicit Discount Rate]) ^ [Useful Life of
Equip.]))
Note 2) Fuel costs are endogenously determined within the model.

【Cost of Top-Down Modeling Part (loss of utility consumption)】
For other energy consumption that is not subject to technology accumulation, the relationshipbetween the final energy price and the amount of energy saved is expressed by the long-term priceelasticity value (electric power: -0.3, non-electric power: -0.4). The integral value can be defined as
the loss of utility consumption, and it is regarded as the emission reduction cost other than theaccumulated technology.

Assumption of Power Generation Facility Cost
Capital costs in2000 [US$/kW]

59
Capital costs in2018 [US$/kW]

1000

1458

1500

2187

1700

2479

Co-firing rate -5%
Co-firing rate -30%
Co-firing rate -20%

+85
+680
+264-+132

+124
+992
+385-+193

Co-firing rate -60%

+271-+135+395-+197

Low efficiency (e.g., diesel)

250

365

Middle efficiency (sub-critical)

650

948

High efficiency (super-critical)

1100

1604

CHP

700

1021

Low efficiency (steam turbine)

300

437

Middle efficiency (combined cycle)

650

948

High efficiency (combined cycle with high temperature)

1100

1604

700

1021

+55

+80

Low efficiency (steam turbine)

2720–2400

3967–3500

High efficiency (combined cycle)

3740–3030

5454–4419

Nuclear power

2743

4000

IGCC/IGFC with CO2 Capture

2800–2050

4083–2989

Natural gas oxy-fuel power

1900–1400

2771–2042

Hydrogen power（FC/GT）

1160

1692

Ammonia power generation (single fuel firing)3040-1444

4433-2106

Electricity storage (e.g., pumping-up)

1000

1458

Note 1) For the DNE21 + model, the price of standard year 2000, is used. The 2018 price shown is converted using the US GDP deflator.
Note 2) Facility costs are assumed to decrease over time within the range shown in the table.
Note 3) This figure is an assumed value for the United States, and is multiplied by the location factor depending on the country / region, and there
is a slight difference (up to + 3% in Japan). Renewable energy is assumed separately (p.24-28)

Coal powerLow efficiency (e.g., Conventional (sub-critical), currently used in developing
countries)
Middle efficiency (e.g., mainly used in developed countries (super-critical) –Combined power generation including Integrated Coal Gasification (IGCC) in the
future)High efficiency (e.g., mainly used in developed countries (super-critical) – Combined
power generation including IGCC and Integrated Coal Gasification Fuel cell
Combined Cycle (IGFC) in the future)
Co-firing of Coal / Biomass(Additional cost to medium and high efficiency coal power
generation)

Co-firing of Coal / ammonia(Additional cost to medium and high efficiency coal power
generation)

Oil power

Gas power

Co-firing of Natural gas /hydrogenBiomass power

CHP(Additional cost to medium and high efficiency natural gas
power generation)

Co-firing rate -20%

Assumption on Technology Advancement of Power
Generating Efficiency for Thermal Power60

Generating efficiency (%LHV)
Coal
power

Oil power

Gas power

Biomass
power

2010

2020

2030

2050

Low efficiency (e.g., Conventional (sub-critical), currently used indeveloping countries)

23.0

24.0

25.0

27.0

Middle efficiency (e.g., mainly used in developed countries (supercritical) – Combined power generation including Integrated Coal
Gasification (IGCC) in the future)

37.8

39.6

41.4

45.0

High efficiency (e.g., mainly used in developed countries (supercritical) – Combined power generation including IGCC and Integrated
Coal Gasification Fuel cell Combined Cycle (IGFC) in the future)

44.0

46.0

48.0

58.0

IGCC/IGFC with CO2 Capture

34.0

35.5

38.5

50.3

Low efficiency (e.g., diesel)

23.0

24.0

25.0

27.0

Middle efficiency (sub-critical)

38.6

40.2

41.8

45.0

High efficiency (super-critical)

52.0

54.0

56.0

60.0

CHP*1

39.0

41.0

43.0

47.0

Low efficiency (steam turbine)

27.2

28.4

29.6

32.0

Middle efficiency (combined cycle)

39.8

41.6

43.4

47.0

High efficiency (combined cycle with high temperature)

54.0

56.0

58.0

62.0

CHP*1

40.0

42.0

44.0

48.0

Natural gas oxy-fuel power

40.7

41.7

43.7

48.7

Low efficiency (steam turbine)

22.0

22.5

23.5

25.5

High efficiency (combined cycle)

38.0

40.0

42.0

46.0

54.0

56.0

58.0

62.0

Hydrogen power (GT/FC)*1 Exhaust heat recovery efficiency is assumed to be 5 to 20% that varies by region, considering supply and demand balance.

Assumption for Rooftop Solar
PV Power Generation Cost in Japan: Time Series
Stock

Flow

61

Assumption for Large-Scale Solar
PV Power Generation Cost in Japan: Time Series
Stock

Flow

62

Assumption for Onshore Wind
Power Generation Cost in Japan: Time Series
Stock

Flow

63

Assumption for Offshore Wind
Power Generation Cost in Japan: Time Series
Stock

Flow

64

Modeling of Synthetic Methane (Methanation)
域外 the Area
Outside域内the Area
InsideHydrogen
水素製造
production(by(副生水素、化石
producthydrogen,fossilfuel/biomass
燃料・バイオマス(+CCU), water(＋CCS)、水電解)

ﾃﾞｨｽﾄﾘﾋﾞｭｰｼｮﾝ

(Sabatier

Recovery CO2 can beobtained from fossil fuel orbiomass combustion
emission, or by DAC. The
most economical one isselected according theassumed scenarios.
Note) In this analysis in order toprovide incentives to use ofsynthetic fuels for the countries
that use the fuels, CO2
emissions are not recorded in
the countries that use them, but
in the countries that produce
them.

Hydrogen
水素需要

ﾊﾟｲﾌﾟﾗｲﾝで
Export bypipeline
他地域に輸出Export by
ﾀﾝｶｰで
tanker
他地域に輸出ﾃﾞｨｽﾄﾘﾋﾞｭｰｼｮﾝ

Distribution

ﾃﾞｨｽﾄﾘDistriﾋﾞｭｰｼｮﾝ
butionHydrogen
水素需要
demandRegasification
再ガス化

CO
2排出
CO
2
emissions

Methanation
ﾒﾀﾈｰｼｮﾝ

(ｻﾊﾞﾃｨｴ反応)
reaction)

Hydrogen is not limited torenewable energy hydrogen(e-gas). The mosteconomical one is selectedaccording the assumed
scenarios.

demandLique液化
factionRecovered
回収CO2
CO2 (DAC(化石燃料もしくfrom fossil
はバイオマス燃焼
fuel or
排出から、DAC)
biomassfunctionalemissions)

Distribution

electrolysis)

CO2emissions
CO2排出

Gas
ガス需要
demandMethanation

ﾒﾀﾈｰｼｮﾝ
(SOEC co-Export by
ﾊﾟｲﾌﾟﾗｲﾝで
pipeline
他地域に輸出(SOEC共電解)
electrolysis)

Electricity
電気

Lique液化
factionExport by
ﾀﾝｶｰで
tanker
他地域に輸出ﾃﾞｨｽﾄﾘﾋﾞｭｰｼｮﾝ

65

Distribution

Gas
ガス需要
demandRegasification
再ガス化

Balance in Methanation（Assumption in 2050）
Sabatier
reaction

SOEC coelectrolysis

Hydrogen1.22 toeCO2

2.33 tCO2

Electricity

15.7 MWh(=1.35 toe)⇒CO2

2.33 tCO2

Methane⇒1 toe

Modeling of Synthetic Oil66

 Hydrogen is not limited to renewable energy hydrogen (e-liquid). The most economical one isselected according to the assumed scenarios.
 Recovered CO2 can be obtained from fossil fuel / biomass combustion emissions or by DAC.
The most economical one is selected according the assumed scenarios.
Balance in synthetic oil generation in 2050
Hydrogen1.25 toeCO2

3.02 tCO2

Electricity

0.02 toe⇒

Synthetic
oil

1 toe
(Available
energy:0.71 toe)CO2 emission

Electricity
Export/Import

Gasolinesynthesis
Audi e-diesel

CO2 emission

Electricity

Hydrogen productionNote) In this analysis in order toprovide incentives to use ofsynthetic fuels for the countries
that use the fuels, CO2
emissions are not recorded in
the countries that use them, but
in the countries that produce
them.

Gasolinedemand(By-product hydrogen,
Fossil fuels/biomass (+CCS),
Water electrolysis)

Export/ImportLight oilsynthesis

Light oildemandCO2 emission

Electricity
Export/Import

Recovered CO2(From fossil fuel/biomass
combustion emissions or
by DAC)Jet fuel
synthesis

Jet fuel
demandModeling and Assumption of H2-based DRI process

67

 The fuel used for existing direct reduced iron (DRI) production is natural gas, etc. (see left Fig).
 H2-based DRI is a process that replaces fuel with hydrogen (see right Fig).
 DNE21+ assumes a set of integrated processes up to EAF and hot rolling in addition to the H2based DRI process [capital cost: 438.1$/(t-cs/yr), H2 consumption: 12.1GJ/t-cs, power
consumption: 695kWh/t-cs]
 In the H2-based DRI acceleration scenario, it is assumed that new construction will be possible
from 2031 (after 2040).

Example of gas-based DRI making process

Demonstration plant for H2-based DRI

https://www.midrex.com/
J. Kopfle et al. Millenium Steel 2007, p.19

https://www.kobelco.co.jp/releases/1201993_15541.html

Co-Generation System (CGS) Assumption
Facility Cost ($/kW, Price in 2000)
2015

2030

Industry (equivalent to 5 MW)

1250

Business 1 (1-2 MW)

1875

Business 2 （0.5MW）

2500
15167

Household （PEFC/SOFC）

2050

3575

3575

Note) The listed price is the price in 2000. The US consumer price index is 1.46 in 2015 if year 2000 is 1.

Efficiency Assumption (LHV%)
Industry (equivalent to 5 MW)
Business 1 (1-2 MW)Business 2 （0.5MW）
Household （PEFC/SOFC）

2015

2030

2050

PGE
HRE
PGE

49.0
36.2
42.3

51.0
34.8
47.5

54.5
31.2
50.7

HRE

36.2

31.0

27.8

PGE
HRE
PGE
HRE

41.0
34.0
39.7
55.3

44.0
31.0
47.8
45.0

47.0
28.0
55.0
37.8

Note) PGE = Power Generation Efficiency, HRE=Heat Recovery Efficiency

68

Vehicle and Fuel Costs
Assumptions: Compact Cars (Example)

69

Vehicle Cost
2015

2020

2030

2050

170

170

180

185

210

209

202

201

Plug-in hybrid (gasoline)

270

248

219

210

Pure electric (EV)

311

305

265

225

Fuel cell (FCV)

598

514

388

244

2015

2020

2030

2050

12.7

13.0

13.5

14.1

31.0

32.2

34.9

36.3

Plug-in hybrid (gasoline)

57.9

59.0

61.3

62.2

Pure electric (EV)

80.1

88.5

101.7

106.6

Fuel cell (FCV)

41.3

43.9

49.6

55.0

Conventional internal
combustion engine
Hybrid (gasoline)*1-million JPY per vehicle

Fuel Cost（ Equivalent to catalog value）
Conventional internal
combustion engine
Hybrid (gasoline)*km per liter

Assumption for Direct Air Capture (DAC)70

 DAC is a technology to capture atmospheric CO2 at low level of about 400ppm, requiring

more amounts of energy than capturing exhaust gas emissions from fossil fuels
combustion.
 On the other hand, DACCS (up to storage) can achieve negative emissions.
Required energy (horizontal
 It is economical to deploy in area closeaxis), Land areas (color),
to CO2 storage and where energy supply
Investments (circle size) etc.
is available at low cost such as low
cost PV.

EW: Enhanced weathering
AR：Afforestation and reforestation

Smith et al. (2015)

Climeworks

Assumed energy consumption and facility costs of DAC in 2020 based on M. Fasihi et al., (2019):
This analyses adopt “Conservative” among 2 scenarios, “Base” and “Conservative”, by Fasihi et al.
Energy consumption （/tCO2）

High temperature (electrification)system (HT DAC)
Low temperature systems（LT DAC）: use of hydrogen or gas for heat

Facility costs（Euro/(tCO2/yr)）

2020

2050

2020

2050

Elec. (kWh)

1535

1316

815

222

Heat (GJ)

6.3 (=1750 kWh)

4.0

730

Elec. (kWh)

250

182

199

Assumption of Implicit Discount Rate in Investment

71

Assumption of implicit discount rate in technology selection
Medium scenario (SSP2)
Power generation

8% ～ 20%

Other energy transition

15% ～ 25%

Energy intensive industry

15% ～ 25%

Automobile
Transportation

Consumer(business /home)(Environmental purchasing layer)

30% ～ 45%
10%

Trucks, buses, etc.

20% ～ 35%

Cogeneration

15% ～ 25%

Hot water supply, air conditioning, etc.

20% ～ 35%

Refrigerator, lighting, etc.

25% ～ 40%

Note 1) Assumed within the range described by region and time point according to GDP per capita. Japan has a lower
limit (deficit) regardless of the time point
Note 2) Countries with high investment risk (with low GDP per capita) tend to have high investment discount rates andbecause energy and basic materials are universal products, equipment depletion rate is low, resulting in low
investment discount rate. On the other hand, the implicit discount rate for purchasing products tends to be high in thetransportation and residential & commercial sectors which has the rapid changes in products due to the high depletion
rate of equipment.
Note 3) e.g., in power generation, 8.2% / yr is used as WACC in the Net CONE calculation of the capacity market in
the US PJM. In the UK National Grid, 7.8% / yr is used and it is consistent level with the 8%/yr of Japan, US, Europe,
etc. of the power generation sector.

【ref.】Marginal Abatement Cost & Total Energy System Cost
72

※ The cost curve is illustrated as an image (in reality, it is complicated[Area cost]：
due to the correlation between technologies)[▲100%Total Energy System Cost]－[Baseline Total Energy System Cost]
Energy System
Cost*1(billion US$/yr)*1：Numbers in parentheses are fluctuations from the reference*2：Nuclear utilization scenarios represent results from 20% and 50% nuclear ratios

Reference
case

1179

―

1.Renewable
Energy 100%

1284(+106)

2.Renewable
EnergyInnovation

1142

(-37)

3.Nuclear
Power
Utilization*2

1166～
1133

(-13～-45)

4.Hydrogen
Innovation

1160

(-19)

5.CCUS
Utilization

1150

(-29)

6.Case where
demanddecreases due
to car sharing

909(-270)

CO2 Marginal Abatement Cost in Japan
CO2 Marginal
Abatement Cost in
2050 [US$/tCO2]
Reference Case

525

1. RE100545

2. RE Innovation469

3. Nuclear Energy
Utilization*

523～503

4. Hydrogen Innovation

466

5. CCUS Utilization405

6. Demand
Transformation509* Nuclear power utilization scenarios show results under a nuclear power ratio of 20% to 50%

73Marginal Cost of Electricity in Japan
74

Marginal Cost of
Electricity in 2050
[US$/MWh]
Reference Case221

1. RE100

485

2. RE Innovation

198

3. Nuclear Energy
Utilization*

215～177

4. Hydrogen
Innovation

213

5. CCUS Utilization

207

6. Demand
Transformation

221* Nuclear power utilization scenarios show results under a nuclear power ratio of 20% to 50%Note) The electricity marginal cost of model estimation in 2020 is 123 US$/ MWh.

World CO2 Marginal Abatement Cost in 2050：
Comparison with Japan
Reference Case

RE Innovation Case

Japan

525

469

US

167

138

UK

181

141

EU

211

169

Others

162

138

75

[US$/tCO2]
Note: CO2 marginal abatement costs are not the marginal costs of electricity but are those of whole energy
systems, and they are determined by the industrial structure, potential economic outlook, the potential
availabilities of decarbonization technologies such as renewables, CCS and nuclear power.

 Japan has a high CO2 marginal abatement cost due to its low-cost renewable energy
potential and low CCS potential.

World Marginal Cost of Electricity in 2050：
Comparison with Japan76

Model Estimated
Value in 2020

Reference Case

RE Innovation Case

Japan

123

221

198

US

57

99

87

UK

99

201

176

France

110

160

147

Germany

115

188

164

Northern Europe

79

127

111

[US$/MWh]
Note 1: The costs exclude power transmission and distribution costs but include grid integration costs of VRE.
Note 2: The analyses consider the grid integration costs of VRE for Japan based on the estimations of the IEEJ model, while
those for other countries are assumed by the original simple assumptions of DNE21+ model. Therefore the cost comparisons
between Japan and other countries will not be appropriate, and rather it will be better to compare with the costs in 2020 withineach country.

 The marginal cost of electricity is increasing in each country to realize carbon neutrality.
However, the increase in Japan tends to be larger than in other western countries.