Japan CCS Forum 2022
December 1st, 2022

The role of CCS and the challenges
for the large deployments
Keigo AkimotoGroup Leader, Systems Analysis Group
Research Institute of Innovative Technology for the Earth (RITE)(Project Professor, Tokyo Institute of Technology)

1. Overview of Technological Measures
for Carbon Neutrality

Image of Primary Energy
for Carbon Neutrality (Net Zero Emissions)
CCU: CO2 Capture and Utilization
CCS: CO2 Capture and Storage
BECCS: Bioenergy with CO2 Capture and Storage
DACCS: Direct Air CO2 Capture and Storage

Energy saving or Reductionin embodied energy of goods/services(incl. Society 5.0)

【Use of overseas resources】
Nuclear

Nuclear
Domestic renewables

DecarbonizedenergyRenewable energy

3

Measures of grid to expand
renewables (incl. storage battery)Use of renewables surplus
for hydrogen Energy savings are important options
even for the net zero emissions.
 For the net zero, large expansions ofrenewable energies are key. On the other
hand, nuclear power, CCS, and NETs arealso important options.
 It is not so simple to achieve net zero
whose measure is renewables +electrification.

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

Fossil fuels w/CCS
Fossil fuels
w/o CCS

Domestic CO2 storage

BECCS, DACCS
Forestation, mineralization (concrete CCU)

Carbon Dioxide Removal (CDR)

Use of overseas CO2
reservoir (postcombustion)【Use of overseas
resources】

Global CCS Outlook (IPCC AR6) for 2 °C and 1.5 °C

4Fig. 6.35

CCS is expected toincrease to meetthe Paris long-termgoals in the world,
while wide ranges
exist among
scenarios.

Several opportunities to achieve CN: IPCC AR6

5“The deployment of CDR tocounterbalance hard-to-abate
residual emissions is
unavoidable if net zero CO2 or
GHG emissions are to beachieved.” (SPM C.11)

Fig. SPM.5

In all scenarios except Low
Demand scenario, other CDR
options as well as large-scaleafforestation are also utilized
to achieve net zero of CO2.
Furthermore, CDR isindispensable for net zero
GHG emissions.

2. Comprehensive and Quantitative Scenarios
for 2050 Carbon Neutrality in JapanThe scenarios were provided to the Energy Strategy Committee in May 2021.
(Some scenarios had been added.)Energy Assessment Model: DNE21+ (Dynamic New Earth 21+)

7

Systemic cost evaluation on energy and CO2 reduction technologies is possible.
Linear programming model (minimizing world energy system cost; with 10mil. decision variables and 10mil. 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 long-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 climatechange, e.g., cap-and-trade system and Environmental Energy Technology Innovation Plan, and also contribute to
IPCC scenario analysis.

Integration Cost of VRES: integration with aPower Generation Mix Model by Univ. of Tokyo and IEEJ

8♦ As DNE21+ is a global model and not suitable for the analysis regarding internal power grid and regional conditions ofrenewable 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 Fujii-Komiyama Laboratory, the University of Tokyo and theInstitute of Energy Economics, Japan.
♦ Time fluctuation of VRE output is modeled based on nationwide meteorological data, e.g., AMeDAS, to estimate theoptimal configuration (power generation and storage system) and the annual operation by linear 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+.

Grid integration costs approximated from theanalysis of the Univ. of Tokyo – IEEJ power
generation mix model＝Assumption on grid
integration costs in DNE21+ (Marginal cost wheneach implementation share is realized）

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 doldrums

Solar PV
太陽光

1
0.8

66

600

55

500

44

0.7
0.6
0.5
0.4
0.3
0.2

31-DecOutput example of PV

1-Dec

1-Nov

1-Oct

1-Sep

1-Aug

1-Jul

1-Jun

1-May

1-Apr

1-Mar

1-Feb

0

1-Jan

0.1

20:00
16:00
12:00
8:00
4:00
0:00

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

33

22[US$/MWh]
System系統統合費用
integration cost
[US$/MWh][¥/kWh]Output(p.u.)

0.9

700

77

風力
Wind

400

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

Overview of Assumed Scenarios

9

GHG emission
reduction in 2050

Technology assumption(cost / performance)

Technology deployment scenario(The least-cost measures in the world = Equal
marginal abatement costs among nations)

Domestic emission
reductions areendogenously
determined.

Standard case

Determined endogenously (cost minimization),with constraints for nuclear power up to 10% andCO2 storage.

Reference case

▲100%

Offset emission credits of overseas

Assuming highshare of RE underStandard case
Assuming eachtechnology isfurther
accelerated or
expanded.

1. Renewable
Energy 100%

(For other than Japan,▲100% for eachwestern country, and▲100% for the others
as a whole)(Note: It is premised that RE is
diffused due to suspected inertial
force in high share RE scenario.)

Renewable energy nearly 100%
(Nuclear power 0%)
Acceleration of RE cost reduction

Determined endogenously, with constraints fornuclear power up to 10% and CO2 storage.

3. Nuclear Power
Utilization

Expansion of nuclear power
deployment

Determined endogenously, with constraints fornuclear power up to 20% and CO2 storage.

4. Hydrogen
Innovation

Acceleration of hydrogen cost
reduction

Determined endogenously, with constraints fornuclear power up to 10% and CO2 storage.

Expansion of CO2 storage
potential

Determined endogenously, with constraints fornuclear power up to 10%. Large CCS storage
potential assumed.

Acceleration of RE cost red. +Constraints of CO2 intern’ltransportation

Determined endogenously, with constraints fornuclear power up to 10% and CO2 storage. No
intern’l transportation of CO2.

Expansion of car-/ride-sharing

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

2. Renewable
Energy Innovation

5. CCS Utilization
6. Synthetic fuelUtilization
7. Demand
Transformation

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

Cost of renewableenergyReference Case*1
1. Renewable
Energy 100%
2. Renewable
Energy Innovation

Standard cost
Low cost

Max. 10%

Standard cost

Max. 20%

Fully autonomous driving(Car ride sharing)Standard cost

Low cost

Standard cost

Domestic storage: max.
91MtCO2/yr;
Overseas transportation：
max. 235MtCO2/yr

Hydrogen production such as
water electrolysis, hydrogenliquefaction facility cost: Halved

Max. 10%

7. Demand
Transformation

CCUS(Storage potential)

0%5. CCS Utilization

6. Synthetic fuelutilization

Cost of hydrogenMax. 10%

3. Nuclear Power
Utilization*2
4. Hydrogen
Innovation

Ratio ofnuclear power

10Standard assumption(no fully autonomous cars)

Standard cost

Domestic：max.
273MtCO2/yr;
Overseas：max.
282MtCO2/yr

Hydrogen production, such as
water electrolysis, facility cost:
Halved;Innovative methanation

Domestic: max. 91Mt,
Overseas: 0Mt

Standard cost

Domestic: max.
91MtCO2/yr;
Overseas：max. 235MtCO2/yr* 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.

Realization and diffusion of fullyautonomous driving and expansion of
car ride sharing after 2030, anddecrease in material production due toreduction of the number of automobiles

GHG Emissions by Sector in Japan in 2050
1400

11

DACCS
Non-CO2 GHG

1200

Process CO2
GHG Emission [MtCO2eq/yr]

1000

LULUCF CO2Other energy conversion

800

Power generation▲63% relative
to 2013600

Residential & Commercial
Other domestic transportation
Domestic aviation

400

Road transportation
200

Other industry
Chemical0

Pulp & Paper
Cement-200

2015

7. Demand Transformation

6. Synthetic fuel Utilization

5. CCUS Utilization

4. Hydrogen Innovation

3. Nuclear Power Utilization

2. RE Innovation

1. RE100

Offset emission credits
of overseas-400

Reference Case

Iron & Steel

Offset emission credit are used in the case ofoffset emission credits of overseas.
Residual GHG emissions are offset by CDR
options in the other cases.

2050

 In the case of offset emission credits of overseas, the emission reduction in 2050 is 63% relative to 2013 in Japan, because
there are offset emission credit opportunities of cheaper NETs options such as BECCS and DACCS outside of Japan.
 For offset of residual GHG emissions, DACCS plays an important role.

CO2 Balances in Japan in 2050
500

CaptureCapture400

DAC

Ammonia production

300
CO2 capture, storage and utilization [MtCO2/yr]

12

Cement200

BF-BOF
Hydrogen production

100

Biomass-fired0

Gas-firedOil-fired-100

Coal-fired

Storage, utilization-200

CO2 geological storage
-300

CCU
Overseas transport

7. Demand Transformation

6. Synthetic fuel Utilization

5. CCUS Utilization

4. Hydrogen Innovation

3. Nuclear Power Utilization

2. RE Innovation

1. RE100

Reference Case

-500

Offset emission credits
of overseas-400

Storage,utilization

2050

 In the RE100 case, fossil fuels + CCS is excluded and BECCS is utilized instead.
 In the case of offset emission credits of overseas, it will be economical that DACCS is implemented outside of Japan.

Total Primary Energy Supply in Japan in 2050

Primary energy supply [Mtoe/yr]

450

13

Gas: non-energy use

400

Oil: non-energy use

350

Imported hydrogen andammonia
Imported biofuel

300

Solar thermal

250

Solar PV
Wind power

200

Nuclear power

150

Hydro and Geothermal

100

Biomass w/ CCUS
Biomass w/o CCUS

50

2015

7. Demand Transformation

6. Synthetic fuel Utilization

5. CCUS Utilization

4. Hydrogen Innovation

3. Nuclear Power Utilization

2. RE Innovation

1. RE100

Offset emission credits
of overseas

0

Reference Case

Synthetic methane
Gas w/ CCUS
Gas w/o CCUS
Synthetic oil
Oil w/o CCUS
Coal w/ CCUS
Coal w/o CCUS

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 CDR, thus serving as carbon-neutral fossil fuels.

All are offset with CDR
in ▲100% scenarios

 For all of the scenarios, CCS is a cost-effective measure. Particularly in 6) syn. fuel case, large amounts of synthetic
fuel supplies can be observed.
 A substantial amount of imports of hydrogen, ammonia and synthetic fuels are observed.

Electricity Supply in Japan in 2050
1600

Solar PV w/o gridWind power w/o grid

1400

Gas and hydrogen /Coal and ammonia
Hydrogen and annmonia

1200

Electricity generation [TWh/yr]

14

Solar thermal

1000

Solar PV
Wind power (offshore)

800

Wind power (onshore)
Nuclear power

600

Hydro and Geothermal

400

Coal and Biomass w/ CCUS
Biomass w/ CCUS

200

Coal and Biomass w/o CCUS

2050

7. Demand Transformation

6. Synthetic fuel Utilization

5. CCUS Utilization

4. Hydrogen Innovation

3. Nuclear Power Utilization

2. RE Innovation

1. RE100

Offset emission credits
of overseas
2015

Reference Case

Biomass w/o CCUS0

Gas w/ CCUS
Gas CGSGas w/o CCUS
Oil w/ CCUS
Oil w/o CCUS
Coal w/ CCUS
Coal w/o CCUS

 In the case of offset emission credits of overseas, relatively large share of gas without CCS including CGS can be seen in Japan.
 Especially for the RE100 case, a surge in integration costs significantly raises marginal cost of electricity supply, causing
considerable decrease in electricity demand. CCS is important.

CO2 marginal abatement cost, energy system cost,and marginal cost electricity in 2050: Japan
CO2 marginal
abatement cost[$/tCO2]

Energy system cost*1[billion US$/yr]

15

Marginal cost ofelectricity[US$/MWh]*2

Baseline (No climate policy
scenario)

ー

986

―

121

Emission credit of overseas

168

1044

[+58]

184

Reference case

525

1179

[+193]

221

1.Renewable Energy 100%

545

1284

[+299]

485

2.Renewable Energy Innovation

469

1142

(-37)

198

523～5031166～1133(-13～-45)

215～177

4.Hydrogen Innovation

466

1160

(-19)

213

5.CCS Utilization

405

1150

(-29)

207

6.Synthetic fuel Utilization

507

1175

(-4)

190

7.Demand Transformation

509

909

(-270)

221

3.Nuclear Power Utilization*3*1 Numbers in blue parentheses are changes from baseline; Numbers in red parentheses are changes from the reference.
*2 The marginal costs include grid integration costs. The electricity marginal cost from model estimation in 2020 is 123 US$/ MWh.
*3 Nuclear utilization scenarios assume a nuclear power ratio from 20% to 50%.

Emission reduction potentials and costs in 2050 by sector and technology:
Japan
CO2 Marginal Abatement Cost [$/tCO2]

Power generation: High efficiency /Shift among fossil fuels
Power generation: CCUS
Power generation: Biomass
Power generation: Hydro / Geothermal
Power generation: Nuclear power
Power generation: Wind power
Power generation: Solar PV

Power generation: Solar thermal
Power generation: Hydrogen / Ammonia

Transport: High efficiency /Shift among fossil fuels
Transport: Zero emission fuels

Other energy conversion

Residential & Commercial: High efficiency /Shift among fossil fuels
Residential & Commercial: Zero emission fuels

Industry: CCUS

Forestation

Industry: High efficiency /Shift among fossil fuels
Industry: Zero emission fuels

DACCS, Mineralization

Power generation: Synthetic methane

Use of bio fuels inRoad Transportation
Concrete products withabsorbed CO2 (for road)
Adoption of hydrogen DRI

Heat supply by
Gas CGS, etc.

Use of syn. liquid fuelsin Road Transportation

Refinery loss reduction due todecrease of petroleum products
demandEnergy saving in energyintensive industries, etc.
Adopting CCS to co-firingof coal / biomass
Shift from coal
to gas CGC

Adopting CCS
to gas power

Ready-mixed
concrete CO2
trace absorption /curing promotion▲16% from2015 level

Use of syn. methane
in Residential &Commercial sector

DACCS will serve as a “backstop”
technology even in Japan, but will
have a dependency on CO2
storage potentials domesticallyand possibilities of transport tooverseas.

DACCS

Adopting CCS
to gas power

Adopting BEV tolight truck, etc.

Hydrogen/ Ammonia
power
generation
BECCS

Solar PV,
Wind power

H2-based
CCS DRI
Reforestation/
rehabilitation

Nuclearpower

CO2 Reduction compared with Baseline [MtCO2/yr]

16

CCS is relatively cheap
options also in Japan(50-250 USD/tCO2 in 2050).

GHG
CO2carbon neutral carbon neutral
Note 1) This analysis shows the result of the estimation under the technology assumption in the “Reference case”.
Note 2) The emission reduction potentials in this analysis should be referenced as a rough guide, as the emission reduction effects by sector / technology will vary depending on the definitionof the variables for sectors, countermeasures, and technologies, etc.

3. Policy Schemes to Mobilize to Investments

Basic Guidelines on Climate Transition Finance As a response to the EU taxonomy,
which is organized by the dualism ofwhether it is green or not, we will focus
on the transition such as energy saving
andenergyconversion
towarddecarbonization
andpromote“transition finance” to promote funding
there.
 In May this year, the Financial Services
Agency,the
MinistryoftheEnvironment, and the Ministry of
Economy,TradeandIndustry
formulated “Basic Guidelines" forlabeling transition bonds and transitionloans based on the international
principles published in December lastyear.
Development of sectoral roadmaps for highemission industries to pave the way for
decarbonization

Published in May in 2021

Source) Japanese government document

18

Development of transition roadmaps by sector (1/2)

METI is developing climate transition roadmaps by sector to support the transition finance.
Those for iron & steel, chemical, electric power, gas, and oil refinery sectors had been developed, and those for cement andpaper & pulp sectors are being developed.

CO2 intensity- High energy efficiency in existing BF- Ferro cokes etc.

Iron and steel- Hydrogen use (Course50)- Partially hydrogen DRI-

Outside hydrogen use (Super COURSE50)
CCUS
100% hydrogen DRI
Large-scale EAF

A part of the emission reduction options
Fuel switching to natural gas

CO2 emissions

♦
♦

19

Petrochemicals (basic)

Chemical

Energy savings
Increases in chemical and material recycling
Fuel switching to hydrogen and ammonia for power (own use)
CCUS (for material switching)
Fuel switching to hydrogen and ammonia for naphtha
Artificial photosynthesis

Plastics and rubber prod.

Process & recycle

inorganic chemistry (soda)

Development of transition roadmaps by sector (2/2)

20Electric power- Ammonia and hydrogen mixed firing (high ratio)- CCUS etc.
- Ammonia and hydrogen firing- CCUS etc.

Gas
- Syn. Methane, syn, LP gas- Energy saving and expansion of gas infrastructure- Deployments of high energy efficiency gas appliances - Hydrogen productions including from overseas- CCUS etc.
- Deployments of cogeneration systems etc.
- Innovative methanation- DAC etc.

Emissions

CO2 intensity- Renewables, nuclear, closing fossil fuels- Biomass mixed firing etc.

Long-term commitment to revenues for newly decarbonized
power through capacity market in power sector (1/2)
Issues for investment

21

New scheme In the capacity market, the revenues for providing kW are uncertain in the future, and there can be large risks ofinvesting in decarbonized power plants (including CCS) which are higher unit costs of kW in general.
 A new scheme for newly decarbonized power which commit the revenues for 20 years will provide from FY2023. Then,a certain part of the investment risks will be reduced.

Long-term commitment to revenues for newly decarbonized
power through capacity market in power sector (2/2)

22Consideration in different lead time
Deadline for power supply
Solar PV
Wind, geothermal
Hydro power
Hydrogen, ammonia,
biomass, LNG withhydrogen/ammonia, CCS

NuclearBattery
LNG (only forlimited years)

 Construction times are different among power sources. Different lead times among power sources are
considered in the new capacity market for long-term decarbonized power.

GX transition bond and carbon price(under discussions)

GX transition bond

23

Carbon pricing

GX investment: over 150 trillion JPY
Mobilizing investment

Mobilizing investment

 Introduction of emissions trading schemes in the future (for just image, ETS with free allocation fromaround 2025, and with auction from around 2028), and subsidy schemes through “GX transition bond” ofover 150 trillion JPY based on the auction revenues in the future.

4. Conclusion

Conclusion

25♦ The Government of Japan decided the 6th Energy Strategic Plan, new Global warming countermeasure
♦

♦

♦
♦
♦
♦

♦

plan in October 2021: carbon neutrality (CN) by 2050, and -46% in 2030.
To achieve carbon neutrality, in principle, primary energy should consist of renewable energy, nuclear
energy, and fossil fuels with CCS. The combination of an increase in electrification ratio and low- andde-carbonized power supply plays a vital role in achieving net-zero emissions.
CCS will play a certain role toward CN in Japan as well as the importance of global strategy including
the utilization of overseas-made renewable energy and CCS through hydrogen, ammonia, e-methane(synthetic gas), and e-fuels (synthetic oil).
Negative emission measures such as DACCS will also play an important role in achieving net-zeroemissions including the opportunities in the implementations overseas with emission credit transfer.
The transition measures and policies will be also very important. The Government of Japan isdeveloping the transition roadmaps for supporting the transition finance.
The policy schemes to mobilize large amounts of investment in decarbonized energy sources (e.g.,
nuclear power, CCS) with high risks for investments are important.
Some policy schemes are under development, and will help to reduce the investment risks also for CCS.
But CCS uses geological formations and they accompany with relatively high uncertainties in actual
amounts of CO2 storage, CO2 injection rate. The needs for the additional policy schemes (or not) should
be discussed.
Not only financial schemes but also developments of several business environment for CCS will also
reduce investment risks.

Appendix

[Supplementary slide]

Concept of Innovation in Power Supply Ref. Value
♦
♦

♦

27

Each power source must overcome a large hurdle to achieve the reference values for power sources in 2050 as presented 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 isnecessary 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 large-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 abovereference 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 a reference 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 location area, solve back-end
problems, secure business feasibility, maintain human resources and technical capabilities, etc. How about deepening discussion on covering 3040% (approx.) with nuclear power which is a carbon-free power source other than renewable energy and hydrogen/ammonia, along withfossil+CCUS/carbon cycle in 2050 as a reference value (* 2)?

Thermal power

Power sources required
innovation

Establisheddecarbonized powersourceIn 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 theimplementation of CCUS / carbon recycling. How about deepening discussion on covering 30-40% (approx.) together with nuclear power which is acarbon-free power source other than renewable energy and hydrogen/ammonia in 2050 as a reference value (* 2)?

Hydrogen,Ammonia

・While having the advantages of adjusting power and inertial force without emitting carbon during combustion, the challenges are establishingtechnology for large-scale power generation, reducing costs, and securing supply. Aim to build a stable supply chain immediately by promoting cofiring 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 and transportation demand. Basedon 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 with hydrogen/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.

Global Baseline Emissions andAssumed Emissions Scenarios under 2°C and 1.5°C
80

CO2 emissions

Net zero CO2 emissions
around 2050
Net zero CO2 emissions
around 2060

40

Net zero CO2 emissions
around 2100

20

-20

-40
2000

Net zero GHG emissions
around 2065

Historical
Baseline

Net zero GHG emissions
around 2100

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

2020

2030

120

2040

2050

2060

2070

2080

2090

Note) Emissions for baseline shows model estimates
results under SSP2, not assumed scenario※ 2DS, B2DS, Below 1.5 °C scenarios assume emission
constraints equivalent to NDCs of each nation up to 2030.

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

2100
GHG emissions [GtCO2eq/yr]

CO2 emissions [GtCO2/yr]

60

0

28

100
80

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

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