Aggregation of Electricity Supply Plans
Fiscal Year 2019

May 2019
Organization for Cross-regional Coordination ofTransmission Operators, JAPAN＜INTRODUCTION＞
The Organization for Cross-regional Coordination of Transmission Operators, Japan(hereafter, the Organization) has aggregated the electricity supply plans for fiscal year
(FY) 2019 according to Articles 29 and 181 of the Operational Rules of the Organization
and Paragraph 1, Article 29 of the Electricity Business Act, which require the plans tobe submitted by electric power companies (EPCOs), and publish their results.
The Organization has aggregated the plans for FY 2019 according to Article 29 of the
Act and Article 28 of the Operational Rules, which were submitted to the Ministry of
Economy, Trade and Industry (METI) under the same article of the Act.
The electricity supply plans are submitted by the EPCOs according to the Network
Code of the Organization, aggregated by the Organization, and sent to METI annuallyby the end of March.
In total, 1,299 electricity supply plans for FY 2019 were aggregated, including 1,296
plans submitted by companies that became EPCOs by the end of November 2018 andthree plans submitted by companies that became EPCOs by March 1, 2019.

Number of Electric Power Companies Subject to the Aggregation in FY 2019
Business License

Number

Generation Companies
Retail Companies

725
535

Specified Transmission, Distribution and Retail Companies

22

Specified Transmission and Distribution Companies
Transmission Companies

52

General Transmission and Distribution Companies

10

Total

1,299

CONTENTS
I. Electricity Demand Forecast ............................................................................................................ 1
1. Actual and Preliminary Data for FY 2018 and Forecast for FY 2019 (Short-Term) ................... 1
2. 10-Year Demand Forecast (Long-Term) ....................................................................................... 3
II. Electricity Supply and Demand ...................................................................................................... 5
1. Supply–Demand Balance Evaluation Method ............................................................................. 5
2. Actual Data for FY 2018 and Projection for FY 2019 (Short-Term)............................................. 6
3. Projection of Supply–Demand Balance for 10 years (Long-Term) ............................................. 10
III. Analysis of the Transition of Power Generation Sources ............................................................ 19
1. Transition of Power Generation Sources (Capacity) .................................................................. 19
2. Transition of Gross Electric Energy Generation ........................................................................ 21
3. Transition of Capacity Factor by Power Generation Sources .................................................... 23
4. Installed Power Generation Capacity and Gross Electric Energy Generation for Each Regional Service
Area................................................................................................................................................. 25
5. Development Plans by Power Generation Sources .................................................................... 26
IV. Development Plans for Transmission and Distribution Facilities............................................... 27
1. Development Plans for Major Transmission Lines .................................................................... 30
2. Development Plans for Major Substations................................................................................. 33
3. Summary of Development Plans for Transmission Lines and Substations ............................... 35
V. Cross-Regional Operation .............................................................................................................. 37
VI. Analysis of Characteristics of Electric Power Companies ........................................................... 40
1. Distribution of Retail Companies by Business Scale (Retail Demand) ..................................... 40
2. Retail Company Business Areas ................................................................................................ 42
3. Supply Capacity Procurement by Retail Companies ................................................................. 43
4. Distribution of Generation Companies by Business Scale (Installed Capacity) ....................... 46
5. Generation Company Business Areas ........................................................................................ 49
VII. Findings and Current Challenges .............................................................................................. 51
VIII. Conclusions ............................................................................................................................... 57
APPENDIX 1 Supply–Demand Balance for FY 2019........................................................................ A1
59
APPENDIX 2 Long-Term Supply–Demand Balance for the 10-year Period FY 2019–2028 ............ A3
61

I. Electricity Demand Forecast
1. Actual and Preliminary Data for FY 2018 and Forecast for FY 2019 (Short-Term)a. Peak Demand (average value of the three h ighest daily loads 1 ) in August
Table 1-1 shows the actual data for the aggregated peak demand for each regional service area 2
submitted by the 10 general transmission and distribution (GT&D) companies for FY 2018 and theforecast3 value for FY 2019.
Peak demand (average value of the three highest daily loads) for FY 2019 was forecast at 159,070
MW, which represents a 0.4% decrease over 159,700 MW, that is, the temperature-adjusted4 value
for FY 2018.
Table 1-1 Peak Demand (average value of the three highest daily loads) in August(nationwide, 104 kW at the sending end)
FY 2018 Actual
FY 2019 Forecast(temperature adjusted)

15,907 (-0.4%)*

15,970* % change compared with actual data for the previous year

b. Forecast for FY 2019
Table 1-2 shows the monthly average value of the three highest daily loads in FY 2019 from theaggregated peak demand for each regional service area submitted by the 10 GT&D companies. The
monthly average value of the three highest daily loads in summer (August) is greater than that inwinter (January) by about 10 GW; therefore, nationwide peak demand occurs in summer.
Table 1-2 Monthly Peak Demand (average value of the three highest daily loads) in FY 2019(nationwide, 104 kW at the sending end)
Apr.
Pea k Demand

11,641Oct.

Pea k Demand

11,887May
11,446
Nov.
12,552Jun.

Jul.

12,74815,872

15,907Jan.

Feb.

14,892

14,870Dec.
14,285Aug.

Sep.
13,899Mar.
13,536

Peak demand (average value of the three highest daily loads) corresponds to the average value of the threehighest daily loads (hourly average) in each month.
2 Peak demand in the regional service areas refers to the average value of the three highest daily loads in publicdemand supplied by retail companies and GT&D companies through the transmission and distribution networkof the GT&D companies. The Organization publishes these average values according to the provisions ofparagraph 5, Article 23 of the Operational Rules.
3 Demand forecast beyond FY 2019 is based on normal weather. Thus, weather conditions for forecast assumption
may vary in contrast to the actual data or estimated value in FY 2018.
4 Temperature adjustment is implemented to capture the current demand based on normal weather, which
excludes demand fluctuations triggered by air-conditioner operation.
11

c. Annual Electric Energy Requirements
Table 1-3 shows the preliminary data 5 for FY 2018 and the forecast value for FY 2019 from theaggregated electric energy requirements of each regional service area submitted by the 10 GT&D
companies. The electric energy requirements for FY 2019 are forecast at 890.5 TWh, a 0.4%
increase over the 886.9 TWh in the preliminary data for FY 2018.
Table 1-3 Annual Electric Energy Requirements(nationwide, TWh at the sending end)
FY 2018 Preliminary
FY 2019(temperature-adjusted)
Forecast
890.5 (+0.4%)*

886.9* % changes over the preliminary value for the previous year.

5

Preliminary data for annual electric energy requirements are an aggregation of the act ual data from April to
November 2018 with the preliminary data from December 2018 to March 2019.

2

2. 10-Year Demand Forecast (Long-Term)
Table 1-4 shows the major economic indicators developed and published on November 28, 2018 by
the Organization, which are assumptions for the GT&D companies to forecast the peak demand intheir regional service areas.
The real gross domestic product (GDP) 6 is estimated at ¥538.3 trillion in FY 2018 and ¥572.5 trillion
in FY 2028 with an annual average growth rates (AAGR) of 0.6%. The index of industrial production(IIP)7 is projected at 104.3 in FY 2018 and 108.5 in FY 2028 with an AAGR of 0.4%.

Table 1-4 Major Economic Indicators Assumed for Demand Forecast
FY 2018

FY 2028

Gross Domestic Product(GDP)¥ 538.3 trillion¥ 572.5 trillion [+0.6%]*

Index of Industrial Product(IIP)

104.3

108.5 [+0.4%]** Average annual growth rate for the forecast value of FY 2018

a. Peak Demand (average value of the three h ighest daily loads) in August
Table 1-5 shows the peak demand forecast for FY 2019, FY 2023, and FY 2028 as the aggregationof peak demand for each regional service area submitted by the 10 GT&D companies. In addition,
Figure 1-1 shows the actual data and the forecast of peak demand from FY 2006 to 2028. The peakdemand nationwide is forecast at 158,140 MW in FY 2023 and 157,350 MW in FY 2028, with an
AAGR of minus 0.1% from FY 2018 to FY 2028.
The peak demand forecast over 10 years shows a slightly decreasing trend, which is largely due tonegative factors, such as efforts to reduce electricity use, wider utilization of energy-saving electric
appliances, a shrinking population, and load-leveling measures, and despite positive factors suchas the expansion of economic scale and greater dissemination of electric appliances.
In addition, the AAGR forecast is lower than that of the previous year, mainly due to a declining
level of economic activity and a decreasing trend in actual electricity demand because of progressin energy conservation.
Table 1-5 Peak Demand Forecast (average value of the three highest daily loads) for August(nationwide, 104 kW at the sending end)
FY 2019 [a forementi oned]

FY 2023

FY 2028

15,907

15,814 [-0.2%]*

15,735 [-0.1%]** Average Annual Growth Rate for the forecast value of FY 2018

6 GDP expressed as the chained price for CY 2011.
7 Index value in CY 2015 = 100

3

Figure 1-1 Actual and Forecast Peak Demand (August for Nationwide, 104 kW at the sending end)b. Annual Electric Energy Requirement
Table 1-6 shows the forecast for annual electric energy requirements in FY 2019, FY 2023, and FY
2028 as the aggregation of the electric energy requirements for each regional service area
submitted by the 10 GT&D companies. The nationwide annual electric energy requirement is
forecast at 884.6 TWh in FY 2023 and 882.1 TWh in FY 2028, with an AAGR of minus 0.1% fromFY 2018 to FY 2028.
The annual electric energy requirement forecast over 10 years shows a slightly decreasing trend,
which is largely due to negative factors, such as efforts to reduce electricity use, wider utilization ofenergy-saving electric appliances, and a shrinking population, and despite positive factors such as
the expansion of economic scale and greater dissemination of electric appliances.
Table 1-6 Annual Electric Energy Requirement Forecast(nationwide, TWh at the sending end)
FY 2019 [aforementioned]

FY 2023

FY 2028890.5

884.6 [-0.1%]*

882.1 [-0.1%]** AAGR for the forecast value of FY 2018.

4

II. Electricity Supply and Demand
1. Supply–Demand Balance Evaluation Method
The Organization will evaluate the supply–demand balance for each regional service area as wellas nationwide using the supply capacity 8 and peak demand data for the regional service areas.
Based on the discussion at the 37th meeting of the Study Committee on Regulating and Marginal
Supply Capability and Long-Term Supply–Demand Balance Evaluation (March 20, 2019), theOrganization will implement its evaluation using the criterion of whether the reserve margin (%) 9for each regional service area is secured over 8% or not, and when the least reserve margin
emerges at the time other than the average value of the three highest daily loads, the least reserve
margin also is secured over 8%.
In the Okinawa EPCO regional service area, the criterion is to secure power supply capacity overpeak demand against an interruption of its largest generating unit and balancing capacity withfrequency control function in its regional service area.
Figure 2-1 summarizes the supply–demand balance evaluation. Supply capacity includes thegenerating capacity requirements secured by retail and GT&D companies for their regional service
areas and the production of surplus power10 of generation companies. The supply capacity currently
secured by retail companies includes power procured 11 from other regional service areas throughcross-regional interconnection lines. Thus, the surplus power of generation companies or reserve
capacity of retail companies might provide supply capacity for other regional service areas in the
future.
Under the circumstances in which the operation of a nuclear power plant has become uncertain, thesupply capacity of the corresponding unit or plant is recorded as zero where the corresponding supply
capacity is reported as “uncertain” according to Procedures for Electricity Supply Plans of FY 2019
(published in December 2018 by the Agency for Natural Resources and Energy). In the electricity
supply plans for FY 2019, supply capacity was reported as “uncertain” by all nuclear power plants
except for those that had resumed operation by the time of the submission of the electricity supply
plans (March 1, 2019).

Supply capacity is the maximum power that can be generated steadily during the peak demand period (averagevalue of the three highest daily loads).
9 Reserve margin (%) describes the difference between supply capacity and peak demand (average value of thethree highest daily loads) divided by peak demand (average value of the three highest daily loads).
10 Surplus power is the surplus power generation capacity of generation companies in a regional service area
without sales destination.
11 In case of congestion in cross-regional interconnection lines, the rebated figure to each area calculated by theOrganization is added.
85Supply Capacity
in regional
service area

SurplusPower

Generation
Company
Supply Capacity

General T&D
Sales
Sales toOther Areas

Reserve capacity in one area will be temporarily evaluated as supply
capacity in the area; however, the reserve capacity can be considered
as supply capacity for another area in case that if there is available
transfer capability in the cross-regional interconnection line between
the two areas.

SupplySales
within Own
Service Area
General T&D
Company
Supply Capacity
Procured from
Non- EPCO(e.g. Solar power by
FIT system, Surplus
purchased from
autoproducers )Retail Company
Supply Capacity

Area B

Area A

SurplusPower
General
T&D

Other

+ 8%
Area

General T&D
SupplyCrossregional
Line

Supply+ 8%

Purchase from
Other Areas

Peak
DemandProcured for
Own Service
Area

Surplus Power

General
T&D

SecuredSupplyCapacityof RetailCompany

Peak
DemandSecuredSupplyCapacityof RetailCompany

Figure 2-1 Summary of Supply–Demand Balance Evaluation

2. Actual Data for FY 2018 and Projection for FY 2019 (Short-Term)a. Actual Data for FY 2018
Table 2-1 shows the actual supply–demand balance in August 2018 based on the nationwide supply
capacity and peak demand data.
A reserve margin of 8%, which is the criterion for stable supply, was secured in all regional service
areas supplied by GT&D companies.
Table 2-1 Actual Supply–Demand Balance in August 2018
(nationwide, 104 kW at the sending end)
Peak Demand
Supply Capacity
Reserve(temperature a djusted) [aforementioned](nationwide)
Capacity
15,97017,891

1,921

Reserve
Margin10.7%

Table 2-2 shows the actual supply–demand balance in each regional service area in August 2018. A
reserve margin of 8% could not be secured in the Tokyo area; a reserve margin of 3%, which is thecriterion for stable daily operation, was secured.

Table 2-2 Actual Supply–Demand Balance in August 2018
(each regional service area, 104 kW at the sending end)
Peak Demand
Supply Capacity
Reserve Margin

Hokkaido Tohoku
419
1,297
550
1,603
31.4%
23.6%

Tokyo
Chubu Hokuriku Kansai Chugoku Shikoku Kyushu Okinawa
5,377
2,473
504
2,639
1,028
504
1,552
150
5,697
2,736
582
2,886
1,222
551
1,877
187
6.0%
10.6%
15.4%
9.4%
19.0%
9.2%
20.9%
24.7%

6

b. Projection of Supply–Demand Balance in FY 2019
Table 2-3 and Figure 2-2 show the projection of a monthly supply–demand balance (at the time of theleast reserve margin) for FY 2019. A reserve margin of 8% is secured for each month nationwide.
Table 2-3 Projection of the Monthly Supply–Demand Balance for FY 2019(at the time of the least reserve margin; nationwide, 10 4 kW at the sending end)
Apr.

May

Jun.

Jul.

Aug.

Sep.

Peak Demand

11,623

11,38912,64015,661

15,68013,826

Supply Capacity

14,67914,53515,016

17,253

17,141

16,303

Reserve Margin

26.3%

27.6%

18.8%

10.2%

9.3%

17.9%

Oct.

Nov.

Dec.

Jan.

Feb.

Mar.

Peak Demand

11,861

12,552

14,285

14,892

14,87013,536

Supply Capacity

14,218

14,668

16,13016,893

16,836

16,228Reserve Margin

19.9%

16.9%

12.9%

13.4%

13.2%

19.9%

Figure 2-2 Projection of the Monthly Supply–Demand Balance for FY 2019(at the time of the least reserve margin; nationwide, at the sending end)

7

Table 2-4 shows the monthly projection of the least reserve margin for each regional service area.
In addition, Table 2-5 shows the monthly projection of the least reserve margin 12 for each regional
service area recalculated using power exchanges to areas below the 8% reserve margin from areasof over 8% reserve margin based on the available transfer capability (ATC)13.
The least reserve margin for each regional service area almost secures the criterion of a stablesupply, with a reserve margin of 8%, except for some areas and months. However, a nationwide
reserve margin of 8% (the criterion of stable supply) is secured by using cross-regional interconnectionlines to share power from other areas with sufficient supply capacity.
Table 2-4 Monthly Projection of the Least Reserve Margins Nationwide and for Each Regional Service Area
(resources within own service area only, at the sending end)
Hokkaido
Tohoku
Tokyo

Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
36.2% 47.4% 57.0% 21.1% 22.2% 24.9% 19.7% 19.5% 25.0% 19.6% 21.5% 23.8%
19.8% 26.8% 16.9% 14.3% 11.5% 13.1%
9.8% 12.0% 11.3% 10.9% 12.0% 12.4%
20.2% 30.8% 18.7%
8.5%
8.7% 22.6% 23.8% 16.5% 20.0% 18.4% 16.7% 23.8%

50 Hz area
Total

21.3% 31.2% 20.9% 10.3% 10.0% 20.9% 20.6% 15.8% 18.6% 16.9% 16.1% 21.4%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

26.9%
28.1%
30.6%
24.1%
42.9%
35.5%

60 Hz area
Total
Interconnected

21.1%
24.0%
25.3%
21.9%
39.9%
26.0%

19.7%
8.4% 10.1% 17.8% 19.0%
15.0% 16.1% 11.0% 15.6% 13.3%
14.0%
6.5%
5.5% 16.0% 19.9%
16.8% 12.6% 11.2% 14.8% 19.3%
30.1% 20.2% 16.1% 14.9% 23.8%
12.7%
9.6%
4.8%
9.3% 16.3%

30.1% 24.5% 16.8%

9.7%

17.2%
8.7% 10.1% 11.8% 17.6%
8.1% 13.7%
9.4%
9.3% 16.2%
19.9%
8.7% 11.8% 10.4% 17.3%
12.6%
0.6%
8.4%
9.8% 16.6%
26.0% 15.8%
4.2%
5.3%
2.4%
15.9%
5.4%
9.6%
9.1% 25.7%

8.3% 15.1% 18.8% 17.1%

7.8%

9.9% 10.1% 17.8%

26.0% 27.5% 18.6%
9.9%
9.1% 17.7% 19.6% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 41.9% 35.7% 33.1% 33.5% 38.1% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.6% 18.8% 10.2%
9.3% 17.9% 19.9% 16.9% 12.9% 13.4% 13.2% 19.9%

Below 8% Criteria

Table 2-5 Monthly Projection of the Least Reserve Margins Nationwide and for Each Regional Service Area
(with power exchanges through cross-regional interconnection lines, at the sending end)
Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
21.3% 29.8% 45.2% 11.3% 12.4% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 22.3%
21.3% 28.9% 17.8% 11.3% 9.0% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 19.3%
21.3% 28.9% 17.8% 9.8% 9.0% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.8% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.5%
Interconnected 26.0% 27.5% 18.6%
9.9% 9.1% 17.7% 19.6% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 41.9% 35.7% 33.1% 33.5% 38.1% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.6% 18.8% 10.2% 9.3% 17.9% 19.9% 16.9% 12.9% 13.4% 13.2% 19.9%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved to over 8%

This evaluation is implemented based on the following. The evaluation of timing of utilization of interconnectionlines varies in the regional service areas; power exchange availability is calculated based on the least reserve
margin, and the calculated results are lower than those based on the reserve margin at a given time. Therefore,
this evaluation covers a more severe condition, which is better for a stable supply.
13 The projection of the reserve margin is based on the ATC of transactions among areas indicated in the electricity
supply plan.
128In the Okinawa EPCO regional service area,14 which is a small and isolated island system unable
to receive power through interconnection lines, the criterion of stable supply is to secure supply
capacity over peak demand by deducting the capacity of the largest generating unit and balancing
capacity with frequency control (‘Generator I’, total of 301 MW), without applying the criteria ofother interconnected areas. Table 2-6 shows the monthly reserve margin against the deduction of
the capacity of Generator I, which indicates the stable supply was secured in each month.

Table 2-6 Monthly Reserve Margin against the Deduction of the Capacity of Generator I (at the sending end)
Okinawa

14

Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
26.4% 17.1% 14.0% 12.7% 13.1% 17.1% 24.2% 27.0% 43.4% 41.3% 48.8% 53.4%

In the Okinawa EPCO regional service area, the evaluation excludes the reserve margins of several isolated islands.

93. Projection of Supply–Demand Balance for 10 years (Long-Term)a. Supply–Demand Balance
Table 2-7 and Figure 2-3 show the annual supply–demand balance projection for a 10-year period.
A reserve margin of 8% is secured each year nationwide.
Table 2-7 Annual Supply–Demand Balance Projection from FY 2019 to 2028
(nationwide at 17:00 in August, 104 kW at the sending end)

2019

2020

2021

2022

2023

Peak Demand

15,556

15,526

15,504

15,483

15,463

Supply Capacity

17,08817,575

17,113

16,98017,303

Reserve Margin

9.8%

13.2%

10.4%

9.7%

11.9%

2024

2025

2026

2027

2028

Peak Demand

15,441

15,421

15,39915,406

15,385

Supply Capacity

17,365

17,48017,476

17,53017,537

Reserve Margin

12.5%

13.4%

13.5%

13.8%

14.0%

Figure 2-3 Mid-to-Long-Term Annual Supply–Demand Balance Projection(nationwide at 17:00 in August, at the sending end)

10

The hours with the least reserve margins vary; for example, 15:00 in the areas of Tokyo, andShikoku 15, 17:00 in the areas of Hokkaido, Tohoku, Chubu, Hokuriku, Kansai, and Chugoku, 19:00
in the Kyushu area, and 20:00 in Okinawa. Reserve margins at each time calculation include someareas and years that cannot achieve the criterion of a stable supply, i.e., a reserve margin of 8%.
However, the criterion of a stable supply is projected to be secured in all areas and years by
sharing power from other areas with sufficient supply capacity through cross-regional
interconnection lines (see Referential Review A).
Table 2-8 shows the annual projection of reserve margins at 17:00 in August judged as the most
severe supply–demand balance for each regional service area from FY 2019 to 2028. Table 2-9
shows these projections recalculated by adding power exchanges for the years and areas of below
8% reserve margin even with additional generated surplus from areas of over 8% reserve margin
based on the ATC.
The evaluation shows that the reserve margin will fall below 8% as follows: in the Tokyo EPCO
regional service area in FY 2022; in the Chubu EPCO area in FY 2021–2028; and in the Kansai
EPCO area in FY 2019, and 2021–2028. However, all areas will be projected to secure 8% reserve
margin required for a stable supply by sharing power from other areas with sufficient supply
capacity through cross-regional interconnection lines during the projected period.
Table 2-8 Annual Projection of Reserve Margins for Each Regional Service Area
(at 17:00 in August, resources within own service area only, at the sending end)
Hokkaido
Tohoku
Tokyo

2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
22.2% 21.3% 36.8% 37.4% 38.5% 39.0% 39.3% 38.7% 50.0% 50.1%
11.5%
8.7% 18.5% 20.0% 20.3% 21.3% 21.8% 24.6% 25.1% 25.7%
9.0% 12.4%
9.8%
6.6%
9.9% 12.1% 16.5% 15.8% 15.5% 15.5%

50 Hz area
Total

10.3% 12.3% 13.1% 11.0% 13.6% 15.4% 18.9% 18.8% 19.3% 19.5%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

10.1%
11.0%
5.5%
11.2%
16.1%
9.1%

60 Hz area
Total
Interconnected

9.2%
11.7%
11.5%
16.2%
30.2%
16.7%

9.1% 13.4%

1.0%
4.2%
4.8%
5.4%
5.6%
6.3%
6.2%
6.7%
10.2%
9.9%
9.9%
9.8%
8.8%
8.6%
8.4%
8.3%
3.3%
4.6%
7.1%
7.5%
3.4%
4.3%
4.7%
4.9%
19.3% 11.0% 14.6% 15.0% 15.6% 16.0% 15.8% 16.1%
13.6% 11.5% 21.2% 21.2% 21.7% 22.1% 22.5% 22.8%
15.5% 16.5% 17.3% 12.1% 12.1% 10.9% 11.0% 11.0%
7.8%

8.1% 10.2%

9.6%

8.4%

8.7%

8.8%

9.1%

9.6% 12.9% 10.1%
9.4% 11.7% 12.2% 13.1% 13.2% 13.5% 13.7%
Okinawa 35.7% 42.1% 36.1% 38.5% 33.9% 41.1% 40.7% 40.0% 39.5% 39.0%
Nationwide 9.8% 13.2% 10.4%
9.7% 11.9% 12.5% 13.4% 13.5% 13.8% 14.0%
Below 8% Criteria

15 At 17:00 beyond the third year of the projection.

11

Table 2-9 Annual Projection of Reserve Margins for Each Regional Service Area
(at 17:00 in August, with power exchanges through cross-regional interconnection lines, at the sending end)
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
12.4% 12.3% 27.6% 27.2% 28.3% 28.8% 29.0% 29.0% 40.4% 40.4%
9.5% 12.3% 9.6% 8.7% 11.2% 11.7% 14.6% 14.8% 14.6% 13.2%
9.5% 12.3% 9.6% 8.7% 11.2% 11.7% 14.6% 14.8% 14.6% 13.2%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.9% 10.5% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
Interconnected
9.6% 12.9% 10.1% 9.4% 11.7% 12.2% 13.1% 13.2% 13.5% 13.7%
Okinawa 35.7% 42.1% 36.1% 38.5% 33.9% 41.1% 40.7% 40.0% 39.5% 39.0%
Nationwide 9.8% 13.2% 10.4% 9.7% 11.9% 12.5% 13.4% 13.5% 13.8% 14.0%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved above Criteria

The Organization did not count newly developing facilities at EPCOs that are not obliged to submit
development plans or at EPCOs that are obliged to submit plans, but that have not reported suchplans. Therefore, the Organization has investigated generating facilities that are not included in
the electricity supply plans, although they were already applied to generator connection to GT&D
companies and submitted construction plans according to the provisions of Article 48 of the Act incooperation with the Government.
As a result, there are 1,300 MW of such generating facilities nationwide; thus, the Organization
includes those facilities to supply capacity and recalculates reserve margins as outlined in Table 2-10.
Table 2-10 Annual Projection of Reserve Margins for Each Regional Service Area
(at 17:00 in August, with power exchanges through cross-regional interconnection lines and generating facilities notincluded in the electricity supply plans , at the sending end)
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuInterconnected

Okinawa
Nationwide

2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
12.4% 13.8% 30.1% 29.7% 30.7% 31.3% 31.5% 31.5% 42.9% 42.9%
9.6% 13.7% 13.2% 14.5% 14.8% 15.5% 16.2% 16.8% 17.3% 14.8%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 16.2% 16.2% 15.8% 14.8%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 10.2% 9.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 10.3% 11.0% 11.8% 12.2% 11.4% 11.5% 11.6% 13.0%
9.6% 13.7% 11.0% 10.2% 12.5% 13.0% 13.9% 14.1% 14.4% 14.6%
35.7% 42.1% 36.1% 38.5% 33.9% 41.1% 40.7% 40.0% 39.5% 39.0%
9.9% 14.0% 11.2% 10.5% 12.7% 13.3% 14.2% 14.3% 14.6% 14.8%

Table 2-11 shows the annual projection of reserve margins with the capacity of 301 MW equivalent
to Generator I in the Okinawa EPCO area deducted, which indicates a stable supply is secured
throughout the period.
12Table 2-11 Annual Projection of a Reserve Margin with the Capacity Equivalent to Generator I in Okinawa Deducted(at 20:00 in August, at the sending end)
Okinawa

2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
13.1% 19.6% 13.6% 16.0% 11.4% 18.7% 18.3% 17.6% 17.2% 16.7%

Table 2-12 shows the annual projection of reserve margins in January for winter peak demands inthe Hokkaido and Tohoku EPCO areas. A stable supply is secured throughout the period.
Table 2-12 Annual Projection of Reserve Margins for Winter Peak Demand in the Hokkaido and Tohoku Areas(at 18:00 in January, at the sending end)

Hokkaido
Tohoku2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
19.6% 20.1% 14.7% 16.5% 16.8% 17.0% 17.1% 27.2% 27.2% 27.2%
10.9% 9.8% 11.2% 12.5% 12.8% 13.3% 13.7% 16.0% 16.5% 16.9%

b. Supply Capacity Secured by GT&D Companies
GT&D companies secure their supply capacity for the demand of isolated island areas throughout
the projected period, and also secure a balancing capacity equivalent to 7% 16 over their peak demandin their regional service areas for FY 2019 by public solicitation. Table 2-13 shows the securedbalancing capacity procured by GT&D companies.
Table 2-13 Secured Balancing Capacity17 Procured by GT&D Companies (%, 104 kW in Okinawa)
Hokkaido Tohoku
Balancing Capacity
7.0%
7.0%

Tokyo
7.2%

Chubu Hokuriku
7.0%
7.0%

Kansai Chugoku Shikoku Kyushu Okinawa
7.2%
6.9%
7.0%
7.0%
30.1

c. Conclusions Concerning Supply–Demand Balance Evaluation
Supply–Demand Balance Evaluation for FY 2019 (short-term): The criterion of stable supply (i.e.,
8% of reserve margin) is secured throughout the areas and for the short-term period.
Supply–Demand Balance Evaluation for FY 2019–2028 (mid-to-long term): The criterion of stablesupply is also secured throughout the areas and for the mid-to-long-term period.
The Organization continuously and carefully evaluates the supply–demand balance, with monitoringof the submission of altering supply plans and the accompanying supply–demand balance.

16 Public solicitation of balancing capacity is implemented so as to secure a balancing capacity equivalent to 7%

over their peak demand in their regional service areas, and its procurement is based on the peak demand of thesecond projected year of the previous electric supply plan. Therefore, the procured balancing capacity may belower than the capacity equivalent to 7% over their peak demand of the current year.
17 The capacity is the ratio of the balancing capacity to the peak demand in the regional service areas of GT&D
companies. The ratios for the Hokkaido and Tohoku EPCO areas are in January, and in August for the otherareas.

13

[Referential Review A][1] For reference, evaluations for the reserve margin for the short term are stated as below.
<Reference 1> Reserve Margin Projection for Each Month in FY 2019(at the peak demand, the sending end, resources within own service area only)
Hokkaido
Tohoku
Tokyo

Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
36.2% 47.4% 59.1% 21.1% 24.0% 24.9% 19.7% 19.5% 25.0% 19.6% 21.5% 23.8%
19.8% 28.5% 19.4% 17.5% 14.7% 14.9% 9.8% 12.0% 11.3% 10.9% 12.0% 12.4%
20.2% 30.8% 18.7% 8.5% 8.7% 22.6% 23.8% 16.5% 20.0% 18.4% 16.7% 23.8%

50 Hz area
Total

21.3% 31.6% 21.5% 10.8% 10.7% 21.3% 20.6% 15.8% 18.6% 16.9% 16.1% 21.4%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

26.9%
28.3%
30.6%
24.1%
42.9%
35.5%

60 Hz area
Total
Interconnected30.1% 24.5% 17.1% 12.7% 11.5% 15.6% 18.9% 17.1%

21.1%
24.0%
25.3%
21.9%
39.9%
26.3%

19.7%
15.0%
14.8%
16.8%
30.1%
13.4%

9.4%
17.2%
9.2%
14.6%
20.2%
18.8%

11.3%
12.3%
8.2%
13.2%
16.1%
14.5%

17.8%
15.6%
16.9%
14.8%
14.9%
10.9%

19.0%
15.9%
19.9%
19.3%
23.8%
16.3%

17.2% 8.7% 10.1% 11.8% 17.6%
8.1% 13.7% 9.4% 9.3% 16.2%
19.9% 8.7% 11.8% 10.4% 17.3%
12.6% 0.6% 8.4% 9.8% 16.6%
26.0% 15.8% 4.2% 5.3% 2.4%
15.9% 5.4% 9.6% 9.1% 25.7%
7.8%

9.9% 10.1% 17.8%

26.0% 27.6% 19.0% 11.9% 11.1% 18.1% 19.7% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 42.7% 38.7% 37.1% 38.0% 41.5% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.8% 19.3% 12.1% 11.4% 18.4% 20.0% 16.9% 12.9% 13.4% 13.2% 19.9%
Below 8% Criteria<Reference 2> Reserve Margin Projection for Each Month in FY 2019(at the peak demand, the sending end, with power exchanges through cross-regional interconnection lines)

Apr.
May
Jun.
Jul.
Aug. Sep.
Oct.
Nov. Dec.
Jan.
Feb. Mar.
Hokkaido 21.3% 29.8% 47.3% 13.7% 14.1% 19.6% 19.7% 16.0% 16.9% 15.4% 14.6% 22.3%
Tohoku 21.3% 29.3% 18.2% 13.7% 10.5% 19.6% 19.7% 16.0% 16.9% 15.4% 14.6% 19.3%
Tokyo 21.3% 29.3% 18.2% 10.0% 10.5% 19.6% 19.7% 16.0% 16.9% 15.4% 14.6% 19.3%
Chubu 30.1% 26.3% 18.2% 12.4% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.3%
Hokuriku 30.1% 26.3% 18.2% 12.4% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.3%
Kansai 30.1% 26.3% 18.2% 12.4% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.3%
Chugoku 30.1% 26.3% 18.2% 12.4% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.3%
Shikoku 30.1% 26.3% 18.2% 12.4% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.3%
Kyushu 30.1% 26.3% 18.2% 14.1% 11.5% 17.0% 19.7% 17.0% 9.1% 11.1% 11.3% 19.5%
Interconnected 26.0% 27.6% 19.0% 11.9% 11.1% 18.1% 19.7% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 42.7% 38.7% 37.1% 38.0% 41.5% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.8% 19.3% 12.1% 11.4% 18.4% 20.0% 16.9% 12.9% 13.4% 13.2% 19.9%
Improved to over 8%14[2] For reference, annual evaluations of the supply–demand balance at 15:00 and 19:00 for the 10year period FY 2019–2028 are presented below.
<Reference 3> Annual Reserve Margin Calculated at 15:00 in August (resources within own service area only, atthe sending end)
Hokkaido
Tohoku
Tokyo

2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
24.0% 23.4% 39.1% 39.7% 40.8% 41.3% 41.6% 41.1% 52.4% 52.5%
14.7% 12.9% 23.1% 25.0% 25.6% 26.9% 27.7% 30.8% 31.6% 32.5%
8.7% 12.0%
9.5%
6.4%
9.5% 11.7% 16.0% 15.2% 14.9% 15.0%

50 Hz area
Total

10.7% 12.8% 13.8% 11.8% 14.3% 16.2% 19.6% 19.6% 20.2% 20.4%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

11.3%
12.3%
8.2%
13.2%
16.1%
14.5%

60 Hz area
Total
Interconnected

10.7%
13.1%
14.3%
16.9%
30.2%
26.6%

2.8%
12.0%
6.3%
20.6%
14.4%
24.3%

6.0%
11.9%
7.8%
14.6%
16.3%
25.5%

6.7%
12.1%
10.3%
19.5%
26.3%
26.6%

7.3%
12.3%
10.8%
20.0%
26.6%
21.0%

7.5%
11.5%
6.8%
20.8%
27.4%
21.0%

8.2%
11.4%
7.9%
21.3%
28.1%
19.7%

8.2%
11.4%
8.3%
20.4%
28.7%
19.8%

8.7%
11.5%
8.6%
20.7%
29.3%
19.9%

11.5% 16.6% 11.1% 12.0% 14.3% 13.8% 12.7% 13.1% 13.2% 13.5%

11.1% 14.9% 12.3% 11.9% 14.3% 14.9% 15.8% 16.0% 16.3% 16.6%
Okinawa 38.0% 44.4% 38.6% 41.1% 36.5% 43.8% 43.4% 42.8% 42.4% 42.0%
Nationwide 11.4% 15.2% 12.5% 12.2% 14.6% 15.1% 16.1% 16.3% 16.6% 16.9%
Below 8% Criteria<Reference 4> Annual Reserve Margin Calculated at 15:00 in August (with power exchanges through cross-regional
interconnection lines, at the sending end)
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
14.1% 13.5% 29.9% 29.5% 30.6% 31.1% 31.4% 31.4% 42.7% 42.8%
10.5% 12.8% 11.0% 11.8% 12.9% 14.4% 15.4% 15.6% 16.1% 15.9%
10.5% 12.8% 11.0% 10.4% 12.9% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 15.3% 11.0% 10.4% 12.9% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 15.3% 11.0% 10.4% 13.6% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 15.3% 11.0% 10.4% 13.6% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 15.3% 11.0% 10.4% 13.6% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 15.3% 11.0% 10.4% 13.6% 14.4% 15.4% 15.6% 15.5% 15.9%
11.5% 22.7% 18.7% 19.6% 20.5% 14.9% 15.4% 15.6% 15.5% 15.9%
Interconnected 11.1% 14.9% 12.3% 11.9% 14.3% 14.9% 15.8% 16.0% 16.3% 16.6%
Okinawa 38.0% 44.4% 38.6% 41.1% 36.5% 43.8% 43.4% 42.8% 42.4% 42.0%
Nationwide 11.4% 15.2% 12.5% 12.2% 14.6% 15.1% 16.1% 16.3% 16.6% 16.9%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved to over 8%15

<Reference 5> Annual Reserve Margin Calculated at 19:00 in August (resources within own service area only, atthe sending end)

Hokkaido
Tohoku
Tokyo

2019
24.6%
18.3%
9.6%

2020
23.5%
14.9%
13.2%

2021 2022
39.3% 39.9%
25.1% 26.6%
10.5% 7.0%

2023
41.0%
26.7%
10.5%

2024
41.5%
27.6%
12.9%

2025
41.8%
28.0%
17.6%

2026
41.2%
30.8%
16.8%

2027
52.9%
31.2%
16.5%

2028
52.9%
31.6%
16.5%

50 Hz area
Total

12.2% 14.2% 15.0% 12.7% 15.4% 17.4% 21.0% 20.9% 21.4% 21.6%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

12.8%
13.8%
10.2%
13.6%
16.1%
4.8%

60 Hz area
Total
Interconnected

10.9% 15.2%

12.1%
13.1%
16.7%
17.1%
30.3%
12.3%

3.2%
11.3%
8.0%
20.7%
14.4%
10.6%

6.8%
17.0%
9.8%
12.2%
12.4%
11.3%

7.6%
10.9%
12.5%
15.9%
22.3%
11.4%

8.3% 8.5% 9.3% 9.3%
16.6% 11.1% 15.2% 9.0%
13.0% 8.5% 9.5% 9.8%
16.1% 16.6% 16.8% 16.5%
22.6% 23.0% 23.3% 23.6%
5.7% 5.6% 4.2% 4.1%

9.2% 10.1% 11.8% 11.5%

9.8%
14.8%
10.0%
16.7%
23.7%
4.1%

9.9% 10.4% 10.1% 10.7%

11.4% 14.8% 11.8% 11.3% 13.4% 14.1% 14.9% 15.1% 15.2% 15.6%
Okinawa 38.4% 44.9% 38.6% 41.0% 36.2% 43.6% 43.1% 42.3% 41.9% 41.3%
Nationwide 11.7% 15.1% 12.1% 11.6% 13.7% 14.4% 15.2% 15.4% 15.5% 15.8%
Below 8% Criteria<Reference 6> Annual Reserve Margin Calculated at 19:00 in August (with power exchanges through cross-regional
interconnection lines, at the sending end)

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
14.5% 14.2% 29.9% 29.4% 30.6% 31.1% 31.4% 31.3% 43.0% 43.0%
11.4% 14.2% 11.3% 12.1% 12.9% 13.6% 16.5% 16.6% 16.3% 14.9%
11.4% 14.2% 11.3% 10.6% 12.9% 13.6% 16.5% 16.6% 16.3% 14.9%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
11.4% 15.2% 11.3% 10.6% 12.9% 13.6% 12.8% 13.2% 12.9% 14.7%
Interconnected 11.4% 14.8% 11.8% 11.3% 13.4% 14.1% 14.9% 15.1% 15.2% 15.6%
Okinawa 38.4% 44.9% 38.6% 41.0% 36.2% 43.6% 43.1% 42.3% 41.9% 41.3%
Nationwide 11.7% 15.1% 12.1% 11.6% 13.7% 14.4% 15.2% 15.4% 15.5% 15.8%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved to over 8%16

[Referential Review B]
Adding Supply Capacity of Generating Facilities Not Included in the Electricity Supply Plans
Figure 2-4 shows mid-to-long-term projections of suspended thermal power plants, which indicatesthat suspended thermal power plants include generators available for rapid power generation thathave the possibility of being counted on as additional supply capacity. Figure 2-5 shows therecalculated projection of mid-to-long-term supply–demand balance(with power exchanges throughcross-regional interconnection lines and generating facilities not included in the electricity supply
plans, at the sending end), which include the additional supply capacity such as the above statedgenerators and the generators with delayed planned outage by the maximum coordination of theirwork schedules.

Figure 2-4 Mid-to-Long-Term Projections of Suspended Thermal Power Plants

Figure 2-5 Annual Projection of Reserve Margins for Each Regional Service Area
(at 17:00 in August, with power exchanges through cross-regional interconnection lines and generating facilities notincluded in the electricity supply plans , at the sending end)17

On the other hand, the reserve margins will decline by 2–5 % after review of the evaluation
method of supply capacity (kW value) of renewable energy*.
* according to the calculation of the expected unavailable energy (EUE) evaluation of renewableenergy generation based on the figures in August, page 37 of document 3 for the 3 rd meeting of the
Subcommittee on Electricity Resilience.

The original document [only in Japanese] is available at
http://www.occto.or.jp/iinkai/kouikikeitouseibi/resilience/2018/files/resilience_03_03_01.pdf
In addition, the necessary supply capacity in severe weather or rare occurrence risk is underreview. It is possible that the minimum necessary supply capacity is secured if proper coordinationof maintenance schedules of generators, or the utilization of suspended thermal generators is
implemented at this moment.

Table 2-14 Supply Capacity of Renewable Energy (EUE Evaluation)[]: Total installed capacity(): Ratio of the supply capacity to the total installed capacity18III. Analysis of the Transition of Power Generation Sources
1. Transition of Power Generation Sources (Capacity)
The installed power generation capacity is the aggregation of the capacity of electric power plants
owned by EPCOs and those owned by companies other than EPCOs that are registered as the
procured supply capacity of retail and GT&D companies.
Table 3-1 and Figure 3-1 show the transition of installed power generation capacity by power
generation sources.
Solar power will notably increase its capacity. Coal- and LNG-fired capacities are also projected toincrease, although they may temporarily decrease through replacement according to future power
development plans for thermal generation. Oil-fired capacity is projected to decrease throughretirement.
Table 3-1 Composition of the Transition of Installed Power Generation Capacities by Power Generation Sources 18(nationwide, 104 kW)

Power Generation Sources FY 2018 (actual)Hydro

FY 2019

FY 2023

FY 2028

4,905

4,911

4,922

4,928

Conventional

2,158

2,164

2,175

2,181

Pumped Storage

2,747

2,747

2,747

2,747

Thermal16,06415,858

16,63016,754

Coal

4,312

4,455

5,240

5,189

LNG

8,201

8,307

8,310

8,485

Oil and others19

3,551

3,096

3,081

3,081

Nuclear

3,804

3,804

3,804

3,804

Renewables

5,740

6,351

7,853

8,703

Wind

380

442

811

1,039

Solar

4,955

5,491

6,553

7,182

Geothermal

49

53

53

53

Biomass

267

287

367

361

Waste

90

79

70

67

Miscellaneous

35

19

19

20

30,54830,94433,22834,209TotalNote) The totals are not necessarily equal due to independent rounding.

18 The installed power generation capacity is the sum of the values submitted by EPCOs.
19

The category ‘Oil and others’ includes the total installed capacities from oil, LPG, and other gas and bituminous
mixture fired capacities.

19

4[10 kW]

Figure 3-1 Transition of Installed Power Generation Capacities by Power Generation Sources (nationwide)20

2. Transition of Gross Electric Energy Generation
Table 3-2 and Figure 3-2 show the transition of gross electric energy generation by power
generation sources aggregated with the reported values submitted by generation companies andthose procured by retail and GT&D companies from companies other than EPCOs.
For nuclear power plants, energy generation is calculated as zero for their capacity reported as“uncertain.” However, the composition of gross electric energy generation may alter according tothe operating conditions of nuclear power plants, change in generation sources, which is specified
as “miscellaneous” in future trends, and regulating measures of generation efficiency by the
Energy Conservation Act.

Table 3-2 Composition of the Transition of Gross Electric Energy Generation by Power Generation Sources 20(nationwide, 108 kWh at the generating end)
Power Generation Sources

Hydro

FY 2018

FY 2019

FY 2023

FY 2028

852

817

847

896

Conventional

791

777

795

806

Pumped Storage

61

40

52

90

Thermal

6,924

6,740

6,110

5,939

Coal

2,764

2,857

3,067

3,160

3,810

3,471

2,756

2,497

350

411

287

282

Nuclear

614

579

593

364

Renewables

846

938

1,234

1,354

Wind

76

88

154

194

Solar

566

627

778

851

Geothermal

23

27

29

29

Biomass

148

171

250

258

Waste

33

25

23

23

Miscellaneous

84

47

65

36

9,319

9,121

8,849

8,588

LNG
Oil and others

Total

19

20

The gross electric energy generation is the sum of the values submitted by EPCOs. For nuclear power plants,
energy generation is calculated as zero for their capacity reported as zero.

21

Figure 3-2 Transition of Electric Energy Generation by Power Generation Sources (nationwide)22

3. Transition of Capacity Factor by Power Generation Sources
Table 3-3 and Figure 3-3 show the capacity factor by power generation sources. The projection of
the capacity factor is calculated using the aforementioned power generation sources and grosselectric energy generation data provided by the Organization.
According to future power development plans, the installed power generation capacity for thermal
generation is projected to increase. However, this does not mean an increase in thermal generation,
as the power supply from renewable energy is projected to increase; therefore, the capacity factorof thermal power plants is projected to decrease gradually.
For nuclear power generation, the installed power generation capacity contains that specified as“uncertain” and the capacity factor appears lower; therefore, this projection does not necessarily
indicate the real capacity factor for nuclear power plants actually in operation.
Table 3-3 Capacity Factors by Power Generation Sources (nationwide) 21

Power Generation Sources

FY 2018

FY 2019

FY 2023

FY 2028

19.8%

18.9%

19.6%

20.8%

Conventional

41.8%

40.9%

41.7%

42.2%

Pumped Storage

2.5%

1.7%

2.2%

3.7%

49.2%

48.4%

41.9%

40.5%

73.2%

73.0%

66.8%

69.5%

53.0%

47.6%

37.9%

33.6%

11.3%

15.1%

10.6%

10.4%

Nuclear

18.4%

17.3%

17.8%

10.9%

Renewables

16.8%

16.8%

17.9%

17.9%

Wind22

22.7%

22.6%

21.7%

21.3%

Solar22

13.0%

13.0%

13.6%

13.5%

Geothermal

55.0%

57.3%

61.6%

61.6%

Biomass

63.3%

68.0%

77.9%

81.6%

Waste

41.8%

36.9%

37.9%

38.3%

Hydro

ThermalCoal
LNG

Oil and others

19

The capacity factor of nuclear power appears lower due to the calculation using the supply capacity reported as“uncertain” and does not indicate the real capacity factor for nuclear power plants.
22 The capacity factors of wind and solar do not consider the decrease due to output shedding.
21

23

Figure 3-3 Capacity Factor by Power Generation Sources (Nationwide) 21

24

4. Installed Power Generation Capacity and Gross Electric Energy Generation for Each Regional Service Area
Figure 3-4 shows the installed power generation capacity for each regional service area at the end of
FY 2018. Figure 3-5 shows the gross electric energy generation for each regional service area in FY
2018.

Figure 3-4 Composition of Installed Power Generation Capacity (kW) for Each Regional Service Area

Figure 3-5 Composition of Gross Electric Energy Generation (kWh) for Each Regional Service Area25

5. Development Plans by Power Generation Sources
Table 3-4 shows the development plans23 up to FY 2028 submitted by generation companies,
according to their new developments, uprated or derated installed facilities, and planned
retirement of facilities in the projected period.
Table 3-4 Generation Development Plans up to FY 2028 by Stages (nationwide, 104 kW)

Power Generation
Sources

New Installation
Capacity

Hydro
Conventional
Pumped Storage

Sites

Capacity

Sites

Capacity

Sites

32.6

41

5.2

47

▵ 20.0

26

32.6

41

5.2

47

▵ 20.0

26

-

-

-

-

1,611.8

41

▵24.0

Coal

824.1

13

-

LNG

781.7

16

-

Oil

6.0

12

▵24.0

ThermalRetirement

Uprating/Derating--▵ 1,009.6

45-▵ 75.63-▵ 528.7

10▵ 405.3

32

1

1

LPG

-

-

-

-

-

-

Bituminous

-

-

-

-

-

-

Other Gas

-

-

-

-

-

-

1,018.0

7

15.2

1

▵ 55.91

Renewables

665.8

379

0.6

2

▵ 32.4

45

Wind

185.9

62

-

-

▵ 17.0

33

Solar

378.0

285

-

-

▵ 0.2

1

Geothermal

4.6

1

Biomass

90.9

26

-

-

▵ 6.9

5

Waste

6.4

5

-

-

▵ 8.3

6

3,328.2

468▵ 1,117.9

117

Nuclear

Total

0.6

▵ 2.9

-

2

51

23 Aggregated including facilities for which the date of commercial operation is “uncertain.”26-

IV. Development Plans for Transmission and Distribution Facilities
The Organization has aggregated the development plans24 for cross-regional transmission lines andsubstations (transformers and AC/DC converters) up to FY 2028 submitted by GT&D andtransmission companies. Table 4-1 shows the development plans for cross-regional transmission
lines and substations. Figure 4-1 shows the outlook for electric systems nationwide. (1), (2), and (3)below list the development plans according to cross-regional transmission lines, major substations,and summaries, respectively.

Table 4-1 Development Plans for Cross-Regional Transmission Lines and Substations
Increased Length of Transmission Lines*25 *26
Overhead Lines*
Underground Lines
Uprated Capacities of Transformers
Uprated Capacities of AC/DC Converters27
Decreased Length of Transmission Lines(Retirement)
Derated Capacities of Transformers(Retirement)

549 km542 km
6 km
17,400 MVA
1,800 MW▵ 108 km
▵ 2,700 MVA

Enhancement plans for cross-regional transmission lines are summarized below.

Interconnection Facility Enhancement Plan between Tohoku and Tokyo(in-service: November 2027)

500kV Transmission Lines･Cross-regional North Bulk Line(prov.): 81 km･Cross-regional South Bulk Line(prov.): 62 km･Soma-Futaba Bulk Line/ Connecting Point Change: 15 km･Shinchi Thermal Power Line/ Cross-regional Switching Station(prov.)
lead-in: 1 km
･Joban Bulk Line/ Cross-regional Switching Station(prov.) Dπ
lead-in: 1 km

Switching Stations

500kV Switching Station(prov.): 10 circuits

24 Development plans for transmission lines and substations are required to be submitted for voltages of more than

250 kV, or within two classes of the highest voltage available in the regional service areas. (For the Okinawa
EPCO, only 132 kV or more is required.) The totals are not necessarily equal due to independent rounding.
25 Development plans corresponding to changes in line category or circuit numbers that were not included inmeasuring the increased length of transmission lines were treated as no change in the length of transmission
lines.
26 Increased length does not include the item with * because of an undetermined in-service date.
27 Installed capacity for the converter station on one side is included in the DC transmission system.

27

Interconnection Facility Enhancement Plan between Tokyo and Chubu(120 MW→210 MW; in-service: March 2021)
AC/DC Converter
Stations･ Shin Shinano AC/DC Converter Station: 900 MW･ Hida AC/DC Converter Station: 900 MW

DC Bulk Line
500kV Transmission Lines･Hida-Shinano DC Bulk Line: 89 km･Hida Branch Line: 0.4 km

Interconnection Facility Enhancement Plan between Tokyo and Chubu(210 MW→300 MW; in-service: FY 2027)
Frequency Converter
Stations･ Shin Sakuma FC station(prov.): 300 MW･Higashi Shimizu FC station: 300 MW→900 MW

275 kV
Transmission Lines･Higashi Shimizu Line (prov.): 20 km･Sakuma Higashi Bulk Line/ Shin Sakuma FC Branch Line (prov.): 3 km
･Sakuma Nishi Bulk Line/ Shin Sakuma FC Branch Line (prov.): 1 km
･Shin Toyone-Toei Line: 1 km
･Sakuma Nishi Bulk Line: 11 km , 2km･Sakuma Higashi Bulk Line: 123 km

500 kV
Transformers･Shin Fuji Substation: 1,500MVA×1･Shizuoka Substation: 1,000MVA×1･Toei Substation: 800MVA×1 →1,500MVA×2

Interconnection Facility Enhancement Plan between Chubu and Kansai(in-service: undetermined)
500 kV
Transmission Lines･Sekigahara Kita Oomi Line: 2 km
･ Sangi Bulk Line/ Sekigahara Switching Station π lead-in: 1 km
･ Kita Oomi Line/ Kita Oomi Switching Station π lead-in: 1 km

Switching Stations･ Sekigahara Switching Station: 6 circuits･ Kita Oomi Switching Station: 6 circuits

28

Ono

Hakodate C.S.
Hokuto C.S.

Higashidori
Kamikita C.S.
Imabetsu C.S.

Kamikita

Iwate

Higashi Hanamaki

Rubeshibe

Miyagi
Chuo

Uenbetsu

NishinoMiyagi

Nishi Tobetsu
Kita Shintoku

Nishi Yamagata

Minami
Hayakita

TomariNatori
Nishi Sendai
Shinchi

ShimogoKyogoku
Minami Iwaki

TomatoAtsumaNishi Futaba

Ono

Kashiwazaki Kariwa

Honna

Okukiyotsudaini

Shiobara

Okukiyotsu

Hakodate C.S.

Shin Iwaki
Shin Tochigi

Shin Motegi
Shin Shinano AC/DC C.S.
Higashi Gunma
Shika
Naka Noto
Shin Nitta
Minami Fukumitsu
Nishi Gunma
Shin Furukawa
Shin
Shin Haruna
Shin Tsukuba
BTB C.S.
Shin Noda
Tokorozawa
Shin Sakado
Higashidori
Shin Okabe
Hida
C.S.
Kamikita C.S.
Kaga
Shin Shinano
Shin Shinano FC
Oku MinoGihoku
Kamikita
Shin Sawara
Kannagaw
Shin
Shin Keiyo
Sekigahara
Tama
a
Shin
Boso
Tsuruga
Higashi
Chichibu
Gifu
Shin Toyosu
Yamanashi
EchizenNanshinEna Shinano
Shin Kisarazu
Takahama Miham
HokubuYahagidaiichi
Kazunogawa Shin Hadano
Shimoinaa
Shin Fuji
Sodegaura
Shin AyabeMaizuru Reinan
Aichi
ToyoneNose
Ooi
Kita Matsue
NishiInagawa
Kyoto
Kita
Higashi Shimizu FC
FuttsuHokusets
Oomi
Seibu
u
ShimaneKeihoku
Tobu Toei
KawaneOkutataragi
Shin Mikawa
Okawachi
Konan
Shin Hiroshima
Sakuma FC
Hino
Chizu
Mie
Shin Nishi Hiroshima
HamaokaShin Sakuma FC (prov.)
YamazakiHigashi
Higashi Okayama Seiban
Nishi Shimane
Oomi
Sunen
Chita
Ihara
MinamiShizuoka
Shin Okayama
Takarazuka
Ushijimacho
Shin Kobe
Kyoto
Higashi
Nishi Nagoya
Kobe
Sakugi
YamatoKongo
Nishi Owari
SakaideShin Ikoma
Shigi
KagawaKasaoka
KihokuKinokawa
Higashi
Kita Onomichi
C.S.
Okuyoshino
Yamaguch
Shin Yamaguchi
Sanuki
Tachibanawan
Awai
Saijo Toyo
Gobo
Anan C.S.
Shin Imaichi

Hokuto C.S.

Imabetsu C.S.

Kita Kyushu
Sefuri

GenkaiShin Tokuyama

Kawauchi

Buzen
Ikata

Chuo

Matsuura
Nishi Kyushu

Higashi
KyushuYuge

Kumamoto
Naka Kyushu
Hitotsuse
Oita

Reihoku

HimukaMinami Kyushu
MiyazakiSendaiLEGEND
Hydro Power Plant

500kVLine or DC Line

Thermal Power Plant

Line under 275kV

Nuclear Power Plant＿ ○Existing Facility

Renewable
Plant
Substation＿ ○In Service during FY 2019

＿ ○In Service from FY 2020 to 2023

＿ ○In Service from FY 2024 to 2028

＿ ○In Service beyond FY 2029
Or to be Determined

Power

Switching Station
AC/DC
StationImaichiMinami Soma
Fukushimadaini
Shin Fukushima
HironoConverter

Frequency Converter
Station, BTB C.S.

＿ ○Ishikawa S.S.

Kin

Ishikawa

Makiminatodaii
chiGushikawa S.S.
Gushikawa

Enobi

Toguchi
Yoshinoura S.S.
Yoshinoura

Makiminato
Kita Naha
Nishi NahaTomoyose

Nishihara

Facility to be Retired

Figure 4 Power Grid Configuration in Japan27
29

1. Development Plans for Major Transmission Lines
Table 4-2 Development Plans under Construction
Compa ny
Hokkaido
EPCO

Tohoku
EPCO

TEPCO
Power
Gri d

Li ne
Ka mi Ya kumo
Swi tching Station
Ka mi Ya kumo Branch
Li ne1408G02
Bra nch Li ne
Cus tomer Li ne/ Natori
Subs tation Dπ lead-in
G3060006
a ccess line (prov.)
Shi nano-Hida
DC Bul k LineShi njuku-Jonan Line
repl acement

Vol ta ge

Length 28,29

Ci rcui t

In-construction

In-s ervi ce

Purpos e 30

187kV

-

2

Aug. 2018

Oct. 2019

Generator connection

187kV

0.2km

1

Ma r. 2019Nov. 2019

Generator connection

500kV

3km

2

Sep.2017

Jul . 2019

Generator connection

275kV

0.4km

2

Ma y 2018

Jun. 2019

Dema nd coverage

275kV

5.6km

2

Ja n. 2017

Apr. 2019

Generator connection

DC±
200kV

89km

BP 1

Jul . 2017

Ma r. 2021

Reliability upgrade*3275kV

16.4km3

Nov. 2017

Jul . 2018(No.1)
Apr. 2020(No.2)
Apr. 2019(No.3)

Agi ng management

2

Ja n. 2019Nov. 2032(No.2)
Nov. 2025(No.3)

Agi ng management

*1,*2

23.4→
5.0km (No.2)
Hi gashi Shi njuku Line
repl acement

275kV*1, *223.4→
5.3km (No.3)*1, *2Chubu
EPCO

Ka ns aiEPCO
Shi koku
EPCO

Shi zuoka Higashi
Bra nch LineShi zuoka Nishi Branch
Li ne
Hi da Branch Line
Kobelco Power
Kobe daini Thermal
Power Li ne
Ma ts uyama Higashi
Li ne

2km

2

Jul .2001

Jun. 2019

275kV

3km

2

Jul .2001

Jun. 2019

500kV

0.4km

2

Jun. 2018

Sep. 2020

Agi ng management
Economic upgrade
Agi ng management
Economic upgrade
Reliability upgrade*3275kV

4.4km*1

3

Apr. 2017

Feb. 2021(No.1)
Feb. 2022(No.2)187kV

47.8km *2

1→2

Aug. 2018

Nov. 2019

500kV

124km

2

Nov. 2014

Jun. 2022

220kV

4km *1*2

1Oct. 2017

Ma y 2019

Agi ng management

220kV

0.3km

1

Oct. 2018

Oct. 2019

Generator connection

Ooma Bulk Li ne

500kV

61.2km2

Ma y 2006

Uncerta i n

Generator connection

NHWETC ToyotomiNa ka gawa Bulk Li ne

187kV

51km

2

Sep. 2018

Sep. 2022

Generator connection

Hyuga Bulk Li ne
Kyus hu
EPCO

275kV

Ka ri ta Thermal-Nissanl i neGNE Togo Mega Solarbra nch line

Generator connection
Agi ng management
Economic upgrade
Rel iability upgrade
Economic upgradeElectricPower
Development
Company(EPDC)
Northern
Hokkaido
Wind Energy
Transmission
Company(NHWETC)

28 Length with *1 denotes “Underground,” otherwise “Overhead.”29 Length with *2 denotes the change of line category or circuit numbers, not included in Table 4.

30 Purpose is stated below: *3 indicates the enforcement relating to cross -regional interconnection lines.

Dema nd coverage
Generator connection
Agi ng management
Rel iability upgrade
Economic upgrade

Rel ating to i ncrease/decrease of demand
Rel ating to generator connection
Rel ating to a ging management of facilities(i ncl uding proper update of facilities with evaluation of obsolescence
Rel ating to i mprovement of reliability or s ecurity of stable supply
Rel ating to i mprovement of economies, s uch as reducing transmission l oss, facility downsizing or
upgra ding stability of the system

30

Table 4-3 Development Plans in the Planning Stages
Compa ny

Hokkaido
EPCO

Tohoku
EPCO

TEPCO
Power
Gri d

Li ne
Toma komai Biomass(prov.) a ccess l ine
Ka mi nokuni daini
Wi nd Power (prov.)a ccess line
Ki ta Horonobe Li ne
pa rtl y uprated
Cros s -regional North
Bul k Li ne(prov.)
Cros s -regional SouthBul k Li ne(prov.)
Soma -Futaba Bulk
Li ne/connecting pointcha nge
Shi nchi Thermal
Power a ccess line /Cros s -regional
Swi tching Station(prov.) l ead-in
Joban Bulk Line/Crossregional Switching
Sta tion(prov.) Dπ lead-in
Cros s -regional
Swi tching Station(prov.)
G7060005
a ccess line(prov.)
MS18GHZ051500
access line (prov.)
Kei hin Li ne No.1&2/connecting pointcha nge

Vol ta ge

Length 28,29 Ci rcui t

In-constructi on

In-s ervi ce

Purpos e 30

187kV

0.2km

1

Apr. 2021

Oct. 2022

Generator connection

187kV

0.1km

1

Ma y 2021

Aug. 2021

Generator connection

187kV

69km

2

Apr. 2021

Jul . 2022

Generator connection

500kV

81km

2

Sep. 2022

Nov. 2027

500kV

62km

2

Sep. 2024

Nov. 2027

500kV

15km

2

Apr. 2022

Nov. 2025

Generator connection
Reliability upgrade*3

500kV

1km

2

Jul . 2024

Jun. 2026

Generator connection
Reliability upgrade*3

500kV

1km

2

Ma y 2025

Jul . 2026

Generator connection
Reliability upgrade*3

500kV

-

10

Ma y 2023

275kV

1km *1

1

275kV

0.1km

275kV

22.7→
23.1km*2(Jun. 2026)

Generator connection
Reliability upgrade*3

Sep. 2020

Apr. 2022

Generator connection

2

Ma r. 2021

Sep. 2021

Generator connection

2

Ma y 2021

Apr. 2022

Generator connection

2

FY 2022

FY 2026

Reliability upgrade*32→3Nov. 2022

Oct. 2023

Dema nd coverage3

Sep. 2019

Aug. 2028(No.1)
Nov. 2032(No.2)
Nov. 2025(No.3)

Agi ng management

Nov. 2027

13km

Hi gashi Shi mizu Line(prov.)

275kV

Ni shi Gunma Bulk Line/Hi gashi Yamanashi
Substation T lead-in

500kV

7km
0.1km(No.1)
0.1km(No.2)
22.1→
21.1km

Shi njuku Line
repl acement

Generator connection
Reliability upgrade*3
Generator connection
Reliability upgrade*3

275kV(No.1) *1, *2

19.9→
21.1km(No.2,3)*1, *2

Chubu
EPCO

Ya ha gi daiichi Branch
Li ne

275kV

5km

1

Aug. 2019Feb.2021

Agi ng management
Economic upgrade

Ena Bra nch Line(prov.)

500kV

1km

2

Ma y 2020

Oct. 2024

Dema nd coverage

500kV

1km

2

Ma r. 2022

Oct. 2024

Dema nd coverage

275kV

8km *22

Apr. 2019

Jun. 2025

Agi ng management
Economic upgrade

500kV

2km

2

Uncerta i n

Uncerta i n

Generator connection*3

500kV

―

6

Uncerta i n

Uncerta i n

Generator connection*3

500kV

1km

2

Uncerta i n

Uncerta i n

Generator connection*3

Shi mo Ina Branch
Li ne(prov.)
Hi gashi Nagoya -Tobu
Li neSeki gahara-Kita Oomi
Li ne
Seki gahara Switching
Sta ti on
Sa ngi Bulk Line/
Sekigahara Switching
Sta tion π lead-in

31Company

Li ne

Ka ns ai
EPCO

Ts uruga Line/ Norths i de improvement
Ooi Bulk Line/Shi n Aya be Li neroute cha nge
Ki ta Ya mato Line/Mi na mi Kyoto
Subs tation
Lea d-in change
Ki ta Oomi
Swi tching Station
Ki ta Oomi Li ne/
Ki ta Oomi Switching
Sta ti on πlead-in
Shi n Kobe Li ne/
rei nforcement
Hi meji LNG Thermal
Power Li ne(prov.)
Shi n Ka kogawa Li ne/
rei nforcement(prov.)

Shi koku
EPCO

Kyus hu
EPCO

EPDC

Length 28,29 Ci rcui t

Vol ta ge

In-cons tructi on

In-s ervi ce

Purpos e 30275kV

9.8km→
9.3km *2

2

Beyond FY 2020

Beyond FY 2023

Agi ng management

500kV

1.9km

2

Jun. 2019

Ja n. 2020

Economic upgrade

500kV

0.1km

2

Aug. 2021

Dec. 2021

Economic upgrade

500kV

－

6

Uncerta i n

Uncerta i n

Generator connection*3

500kV

0.5km

2

Uncerta i n

Uncerta i n

Generator connection*3

275kV

20.2→
21.5km *2

2

Apr. 2019

Jul . 2020

Generator connection
Agi ng management275kV

0.9km *1

1

Feb. 2021

Jun. 2024

Generator connection

275kV

25.3→
25.3km *2

2

Jul . 2021

Jun. 2025

Generator connection
Agi ng management

Sa i jo Thermal Powera ccess line
JR Shi n Isahaya
Bra nch Li ne
Sa i bu Gas/ Hibiki
Thermal Power Li ne
Shi n Ka goshima Line/Sendai Nuclear Powerπ l ea d-in
Sa kuma Higashi Bulk
Li ne/ Shin Sakuma FC
Bra nch Li ne(prov.)
Sa kuma Nishi Bulk
Li ne/ Shin Sakuma FC
Branch Line (prov.)

187kV

6.5km *2

2

Nov. 2019

Ma y 2021

Generator connection

220kV

1km

2

Jul . 2019

Apr. 2021

Dema nd coverage

220kV

4km

2

Feb. 2021

Feb. 2023

Generator connection

220kV

2→5km *2

1→2Aug. 2020

Jul . 2023

Economic upgrade

275kV

3km

2

FY 2022

FY 2026

Reliability upgrade*3

275kV

1km

2

FY 2022

FY 2026

Reliability upgrade*3

Shin Toyone-Toei Line

275kV

1km

1

FY 2022

FY 2026

Reliability upgrade*3

275kV

10.6→
11km *2

2

FY 2022

FY 2027

Reliability upgrade*3

275kV

2km

2

FY 2022

FY 2026

Reliability upgrade*3

275kV

123.7→
123km *2

2

FY 2022

FY 2027

Reliability upgrade*3

Sa kuma Nishi Bulk
Li ne
Sa kuma Nishi Bulk
Li ne
Sa kuma Higashi Bulk
Li ne

Table 4-4 Retirement Plans
Compa ny
Shi koku EPCO
EPDC

Li ne

Vol ta ge

LengthCi rcui t

Reti rement

Ki ta Ma tsuyama Li ne

187kV△47.5km1

Nov. 2019

Shi n Toyone-Toei Li ne275kV△2.6km1

FY 2026

Purpos e 30
Agi ng management
Economic upgrade
Reliability upgrade*3

Sa kuma Nishi Bulk Li ne

275kV△58.0km2

FY 2026

Economic upgrade32

2. Development Plans for Major Substations
Table 4-5 Development Plans under Construction
Compa ny
Hokkaido
EPCO
TohokuEPCOTEPCOPower Grid

Chubu
EPCO

Ka ns ai
EPCO
Chugoku
EPCO
Oki nawa
EPCO
NHWETC

Subs ta ti on 31
Mi na mi Hayakita

Vol ta ge
187/66kV

Ca pa ci ty
200MVA

Number1

In-construction
Aug. 2018

In-s ervi ce
Sep.2019

Purpos e 30
Generator connection

Uenbetsu

187/66kV

75MVA→
100MVA

1→1

Feb. 2019Nov. 2019

Aging management

Na tori *4

275/154kV

450MVA×2

2

Feb. 2017

Jun. 2019

Demand coverage

Shi n Keiyo

275/154kV

300MVA×2→
450MVA×2

2→2

Jul . 2018

Sep. 2019(5B)
Apr. 2021(6B)

Aging management

Shi n Shinano AC/DC
Converter Sta tion*4
Ueno

－

－

-

Ma r. 2016

Ma r. 2021

Reliability upgrade*3

275/66kV

300MVA

1

Feb. 2019

Dec. 2019

Shi zuoka*4

500/275kV

1,000MVA

1

Aug.2001

Jun.2019

Economic upgrade
Aging management
Economic upgrade

－

－

－

Aug. 2017

Ma r. 2021

Reliability upgrade*3

1→1

Feb. 2019

Ma y 2020

Aging management

1→1

Dec. 2018

Oct. 2019

Aging management

1

Ma y 2017

Apr. 2019

1→1

Jul . 2018

Apr. 2019

2→2

Oct. 20173

Apr. 2019

Hi da Converter
Sta ti on*4
Shunen275/154kV

Kona n275/77kV

Hi gashi Ya maguchi

500/220kV

Shi n Tokuyama

220/110kV

Tomoyos e

132/66kV

Ki ta Toyotomi*4

187/66kV

450MVA×1→
300MVA×1
300MVA×1→
200MVA×1
1,000MVA
150MVA×1→
300MVA×1
125MVA×2→
200MVA×2
165MVA×3

Jun. 2020
Oct. 2023
Sep. 2022

Demand coverage
Generator connection
Aging management
Generator connection
Aging management
Generator connection

Table 4-6 Development Plans in the Planning Stages
Compa ny
Hokkaido
EPCO

TEPCO
Power
Gri d

Chubu
EPCO

Subs ta ti on 31

Vol ta ge

Ca pa ci ty
60MVA×2→
100MVA
100MVA×2
100MVA×1→
150MVA

NumberIn-construction

In-s ervi ce

Purpos e 30

2→1

Ma r. 2021

Oct. 2021

Aging management

2

Jul . 2020

Jul . 2022

Generator connection

1→1

Feb. 2022

Oct. 2022

Aging management

Rubeshibe

187/66kV

Ni s hi Nakagawa(prov.)

187/100kV

Ki ta Ebetsu

187/66kV

Shi n Motegi

500/275kV

1,500MVA

1

Nov.2019

Ma r. 2021

Generator connection

Shi n Kisarazu

275/154kV

450MVA×2

2

Jun. 2020

Apr. 2022

Generator connection

Hi gashi Ya manashi

500/154kV

750MVA

1

Apr. 2019

Dec. 2022

Demand coverage

Shi n Tochigi

500/154kV

750MVA

1

Apr. 2021

Ja n. 2023

Generator connection

Shi n Fuji

500/275kV

1,500MVA1

FY 2023

FY 2026

Reliability upgrade*3

Ki ta Tokyo

275/66kV

300MVA

1

Sep. 2020

Jun. 2022

Economic upgrade

Chi ta Thermal Power275/154kV

300MVA×1→
450MVA×1

1→1

Jul . 2019

Apr. 2021

Aging management

Chi ta Thermal Power275/154kV

450MVA×2

2

Jul . 2019Nov. 2020(N1B)
Aug. 2021(N2B)

Generator connection

Ena (prov.) *4

500/154kV

200MVA×2

2

Dec. 2020

Oct. 2024

Demand coverage

Shi mo Ina(prov.) *4

500/154kV

300MVA×2

2

Dec. 2020

Oct. 2024

Demand coverage

Toei

500/275kV

800MVA×1→
1,500MVA×2

1→2

Nov. 2020

FY 2024(N2B)
FY 2026(1B)

Reliability upgrade*3

31 Substation with *4 denotes a substation or converter station newly installed, including an uprated electric facility.

33Compa ny
Chubu
EPCO

Ka ns ai
EPCO

Chugoku
EPCO
Shi koku
EPCO
Kyus hu
EPCO
EPDC

Subs ta ti on 31
Shi zuoka

Vol ta ge
500/275kV

Hi gashi Shimizu－

Hi gashi Os aka

275/77kV

Ni s hi Kobe

275/77kV

Koto

275/77kV

Yodogawa

275/77kV

Ka i nannko

275/77kV

Sa kugi
Shi n Yamaguchi

220/110kV
220/110kV

Ka s aoka

220/110kV

Ni s hi Shimane

500/220kV

Kochi

187/66kV

Ha ya miKi ri s hima
Ma ts ushima
Shin Sakuma FC (prov.)

220/66kV
220/66kV
220/66kV－

Ca pa ci ty
1,000MVA
300MW→
900MW
300MVA→
200MVA
200MVA×2→
300MVA
200MVA→
300MVA
300MVA×2→
300MVA
300MVA×1,
200MVA×2→
300MVA×2
200MVA
400MVA
250MVA→
300MVA
1,000MVA
200MVA→
300MVA
250MVA
300MVA
150MVA－

Number1

In-construction
FY 2024

In-s ervi ce
FY 2026

Purpos e 30
Reliability upgrade*3－

Feb. 2021

FY 2027

Reliability upgrade*3

1→1Sep. 2019

Jun. 2020

Aging management

2→1

Nov. 2020

Jun. 2021

Aging management

1→1

Oct. 2021

Oct. 2022

Aging management

2→1

Dec. 2020

Oct. 2021

Aging management

3→2

Jun. 2021

Jun. 2024

Aging management

12Jun. 2019
Apr. 2019Nov. 2020
Jun. 2021

Generator connection
Economic upgrade

1→1Aug. 2020

Jun. 2021

Aging management

1

Apr. 2020

Ma r. 2022

1→1

Nov. 2021

Apr. 2022

1
1
1

Apr. 2019Nov. 2019
Apr. 2019
FY 2021Jun. 2020
Sep. 2021
Ma r. 2020
FY 2027

Generator connection
Aging management
Dema nd coverage
Generator connection
Generator connection
Economic upgrade
Reliability upgrade*3

Reti rement
Ma r. 2020
Ma r. 2021
Oct. 2020Feb. 2023
Jun. 2019
Ja n. 2021
Sep. 2022

Purpos e
Dema nd coverage
Dema nd coverage
Economic upgrade
Economic upgrade
Aging management
Aging management
Aging management

Table 4-7 Retirement Plans
Compa ny
TEPCO
Power Gri d
Chubu EPCO
Ka ns ai EPCO

Subs ta ti on
Shi n Noda
Ha namigawa
Ki ta Tokyo
Ageo
ShunenHi gashi Osaka
Koto

Vol ta ge
275/154kV
275/66kV
275/154kV
275/66kV
500/275kV
275/154kV
275/77kV

Ca pa ci ty
Number△300 MVA△1△300 MVA△1△300 MVA△1△300 MVA△1△1,000 MVA△1△300 MVA△1△100 MVA×2△2

Other development plans (not subject to submission by the electric supply plan)
The development plan stated below is not required to be included in the electricity supply plan, butwill be implemented as a functional improvement by Chubu EPCO and Hokuriku EPCO.
◇Minami Fukumitsu Interconnection Facility・Substation 500 kV AC Connecting Bus Line
Addition ( in service: October 2019).

34

3. Summary of Development Plans for Transmission Lines and Substations
Tables 4-8 to 4-11 show the summarized development or extension plans of major transmission
lines and substations (transformers and converter stations) up to FY 2028 submitted by GT&D andtransmission companies.

Category

Newly
InstalledorExtended

Table 4-8 Development Plans for Major Transmission Lines
Extended
VoltageLines
Length32
Total Length
Length33
291 km*34
583 km*Overhead
500kV
291 km*Underground
0 km
0 km
Overhead
36 km
66 km
275kV
42 km
Underground
6 km
15 km
Overhead
5 km
10 km
220kV
5 km
Underground
0 km
0 km
121 km241 kmOverhead
187kV
121 kmUnderground
0 km
0 km
Overhead
0 km
0 km
132kV
0 km
Underground
0 km
0 km
Overhead
89 km
89 km
DC
89 km
Underground
0 km
0 km
Total
275kV

To be Retired

187kV
Total

Overhead

Overhead542 km
6 km
△61km
0km
△ 48 km
0 km△108 km

989 km
15 km△119km0km△ 48 km
0 km△166 km

Underground

0 km

0 km

Underground

Overhead
Underground

Overhead
UndergroundTotal Extended
Length583 km*
81 km
10 km
241 km0 km
89 km

549 km1,004 km

△61km

△119km△ 48 km△ 48 km△ 108 km

△ 166 km

Table 4-9 Revised Plans for Line Category and the Numbers of Circuits 35
Voltage
Length Extended
Total Extended Length
500kV
275kV

0 km
311 km

1 km
702 km

220kV
187kV
132kV

9 km
54 km
0 km

14 km
109 km
0 km

DC

0 km

0 km

Total

375 km825 km32 Length denotes both the increased length due to newly installed or extended plans, and the decreased length due

to retirement. Development plans corresponding to the change of line category or the number of circuits were notincluded in the increased length of transmission lines shown in Table 4 -8 and are treated as no change in thelength. The totals of lengths are not necessarily equal due to independent rounding.
In addition, the overall total length is not necessarily equal due to independent rounding.
33 Total length denotes the aggregation of length multiplied by the number of circuits. Development planscorresponding to the change of line category or the number of circuits were not included in the increased length oftransmission lines in Table 4-8 and are treated as no change in the length.
34 See footnote 26.
35 Table 4-9 aggregates the extended and total extended lengths corresponding to the revised pl ans for the line
category and the number of circuits.

35

Table 4-10 Development Plans for Major Substations
Increased
Numbers

Increased Capacity

13

11,700 MVA[5][2,000MVA]

53,000 MVA

[2][900MVA]

6[0]

1,500 MVA
[0MVA]

5

1,050 MVA

[5][695MVA]

0150 MVA[0][0MVA]

Total

29
[12]

17,400 MVA[3,595MVA]

500kV

△1

△ 1,000 MVA

275kV

△7

△1,700 MVA

To be

220kV

0

0 MVA

Retired

187kV

0

0 MVA

132kV

0

0 MVA

Total

△8

△ 2,700 MVA

Category36

Voltage37
500kV
275kV

Newly

220kV

InstalledorExtended

187kV

132kV

[ ]：The aforementioned increase in the number of transformers resulted from new substation
installations.

Table 4-11 Development Plans for AC/DC Converter Stations
Category
Newly
InstalledorExtendedCapacity38

Company and Number of Sites
TEPCO Power Grid

1

Chubu EPCO

2Electric Power Development Company

1

900MW
900MW
600MW
300MW

36 Retirement plans with transformer installations are included in Newly Installed or Extended, and negativevalues are included in the increased numbers or the increased capacity.

37 Voltage class by upstream voltage.

38 Installed capacity of the converter stations on both sides of the DC lines is included.

36

V. Cross-Regional Operation
Retail companies will procure the supply capacity for their customers in their regional service areas.
The scheduled procurement from the external service areas at 15:00 in August 2019 is illustrated infour figures. Figures 5-1 and 5-2 show the supply capacity and the ratio of the supply capacity,respectively, at 15:00 in August. Figures 5-3 and 5-4 show the energy supply and the ratio of theenergy supply, respectively, in FY 2019.
Higher ratios for procurement from the external regional service areas are observed in Tokyo, Kansai
and Chugoku EPCO areas; those to the external regional service areas are observed in Tohoku,
Shikoku and Kyushu EPCO areas. Higher energy is transmitted from other areas to Tokyo, Kansai,
Chugoku, and Shikoku EPCO areas by 10% and over.

Figure 5-1 Scheduled Procurement of Supply Capacity from External Regional Service Areas

37

Figure 5-2 Ratio of Scheduled Procurement of Supply Capacity from External Regional Service Areas

Figure 5-3 Scheduled Procurement of Energy Supply from External Regional Service Areas

38

Figure 5-4 Ratio of Scheduled Procurement of Energy Supply from External Regional Service Areas

39

VI. Analysis of Characteristics of Electric Power Companies
1. Distribution of Retail Companies by Business Scale (Retail Demand)
In total, 535 retail companies submitted their electricity supply plans, and these are classified by
the business scale of the retail demand forecast by the corresponding companies. Figures 6-1 and 62 show the distributions of the business scale of retail demand and the accumulated retail demand
forecast by the corresponding companies, respectively. Notably, small-to-medium-sized retailcompanies (business scale of under 1 GW) plan to expand business.

Figure 6-1 Distribution by Business Scale of the Retail Demand by Retail Companies

Figure 6-2 Distribution by Accumulated Retail Demand by Retail Companies

40

Similarly, retail companies are classified by the business scale of the retail energy sales forecast by
the corresponding companies. Figures 6-3 and 6-4 show the distributions of the business scale ofretail company energy sales and their accumulated energy sales forecast, respectively. Similarly,
small and medium-sized retail companies (business scale of under 1 GW) plan to expand business.

Figure 6-3 Distribution by Business Scale of Retail Company Energy Sales

Figure 6-4 Distribution by Retail Company Accumulated Energy Sales

41

2. Retail Company Business Areas
Figure 6-5 shows the ratio of retail companies by the number of areas where they plan to conduct
their business. Figure 6-6 shows the number of retail companies by their business planning areas
in FY 2019. The figures exclude 68 retail companies that had not yet developed their retailbusiness plans. Half of the retail companies plan their business in a single area.

Figure 6-5 Ratio of Retail Companies by the Number of Planned Business Areas in FY 2019

Figure 6-6 Number of Retail Companies by their Business Planning Areas in FY 2019
Figure 6-7 shows the number and the retail demand of retail companies in each regional service
areas for GT&D companies in FY 2019. In general, the number of companies is comparable withthe scale of retail demand in the regional service area.
42

Figure 6-7 Number and Retail Demand of Retail Companies in Each Regional Service Area

3. Supply Capacity Procurement by Retail Companies
Table 6-1 and Figure 6-8 respectively show the supply capacity secured by retail companies
according to their forecasted demand, and the ratios of the secured supply capacity 39 for the 10year period FY 2019–2028, respectively. Particularly in the mid-to-long term, retail companies
have planned their supply capacity as “unspecified procurement.”40
Table 6-1 Supply Capacity Secured by Retail Companies According to Their Demand for the 10-year Period FY 2019–2028(at 15:00 in August, 104 kW at the sending end)

FY 2019
Peak Demand
Nationwide
Secured Supply
Capacity
Ratio39

Ratio39

FY 2021

FY 2022

FY 2023

15,907

15,877

15,855

15,833

15,814

15,334

15,36814,721

14,453

14,239

96.4%

96.8%

92.8%

91.3%

90.0%

FY 2024
Peak Demand
Nationwide
Secured Supply
Capacity

FY 2020

FY 2025

FY 2026

FY 2027

FY 2028

15,792

15,771

15,74915,757

15,735

14,11014,015

12,112

12,105

12,048

89.3%

88.9%

76.9%

76.8%

76.6%

39

Ratio of the secured supply capacity to areal peak demand is the sum of secured supply capacity of retailcompanies divided by the peak demand nationwide, expressed in %.
40 “Unspecified procurement” means that retail companies plan to procure their future supply capacity by means ofvarious procurement choices, including procurement from the market, as described in the format of theelectricity supply plan.

43

Figure 6-8 Supply Capacity Procured by Retail Companies According to Their Demand for the 10-year Period FY 2019–2028(at 15:00 in August; at the sending end)

Figure 6-9 shows the retail demand forecasted in the regional service area by the retaildepartment of former general electric utilities and their procured supply capacity to the retaildemand. The retail and generation department of the former general electric utilities securesufficient supply capacity procured to the retail demand of their own area.

Figure 6-9 Ratio of Secured Supply Capacity to Forecast Retail Demand of Their Own Area
for Former General Electric Utilities 41 (at 15:00 in August, at the sending end)
41 Includes surplus power of group companies deducting balancing capacity to the secured supply capacity by retailcompanies.

44However, according to a review by the Organization, the ratio of secured supply capacity to forecast
retail demand of the external areas that retail departments of former general electric utilities
forecast as their own demand (including the demand of companies consisting of those majorly
funded by former general electric utilities) has a tendency of procuring the supply capacity as“unspecified procurement”, as is the case with other power producers and suppliers (PPSs) in the
more competitive conditions among the former general electric utilities. In addition, the ratio ofsecured supply capacity procured by other PPSs to their own forecast peak demand nationwide will
decline in the mid-to-long term as indicated in Figure 6-10.

Figure 6-10 Ratio of Procured Supply Capacity to Forecast Retail Demand by Former Electric Utilities in theExternal Areas (left) and by PPSs (right) (at 15:00 in August, at the sending end)
Figure 6-11 shows the secured supply capacity (including surplus power) nationwide of retaildepartments of former general electric utilities (including companies consisting of those majorly
funded by former general electric utilities). The retail departments of former general electricutilities have secured sufficient supply capacity for both their own service area and other externalareas.

Figure 6-11 Ratio of Procured Supply Capacity to Forecast Retail Demand by Former Electric Utilities andCompanies Consisting of Those Majorly Funded by Former Electric Utilities (at 15:00 in August, at the sending end)45

4. Distribution of Generation Companies by Business Scale (Installed Capacity)
In total, 725 generation companies submitted their electricity supply plans, and these areclassified by the business scale of the installed capacity operated by the corresponding companies.
Figure 6-12 shows the distribution by business scale and Figure 6-13 shows the installed capacity
operated by the corresponding companies.
Generation companies with an installed capacity of under 100 MW are planning to enlarge thescale of their business.

Figure 6-12 Distribution by Business Scale of Generation Company Installed Capacity

Figure 6-13 Distribution by Generation Company Accumulated Installed Capacity46

Similarly, generation companies are classified by the business scale of the corresponding company
energy supply forecast. Figure 6-14 shows the distribution by the business scale of the energy
supply and Figure 6-15 shows the distribution by the corresponding company accumulated energy
supply forecast.
Generation companies with an energy supply of under 10 TWh are planning to decrease theirenergy generation.

Figure 6-14 Distribution by Business Scale of Generation Company Energy Supply

Figure 6-15 Distribution by Generation Company Accumulated Energy Supply

47

Figure 6-18 shows the number of generation companies by the power generation sources of theirown generators at the end of FY 2019. The figures exclude 84 generation companies that do not
own their generation plants. Approximately 75% of all generation companies solely own renewableenergy generation facilities.

Figure 6-16 Number of Generation Companies by Power Generation Sources48

5. Generation Company Business Areas
Figure 6-17 shows the ratio of generation companies to the number of areas where they plan to
conduct their business. Figure 6-18 shows the number of generation companies by their businessplanning areas in FY 2019. The figures exclude 117 generation companies that do not own theirgeneration plants. Approximately 75% of all generation companies plan their business in a single
area.

Figure 6-17 Ratio of Generation Companies by the Number of Planned Business Areas in FY 2019

Figure 6-18 Number of Generation Companies by Their Business Planning Areas in FY 201949

Figure 6-19 shows the number and installed capacity of generation companies in each regional
service area for GT&D companies in August 2019. In the Hokkaido, Tohoku, Chugoku, Shikoku,
and Kyushu regional service areas, the scale of generation companies is rather small and their
supply capacity is comparatively small despite the number of generation companies in theseregional service areas.

Figure 6-19 Number and Installed Capacity of Generation Companies in Each Regional Service Area50

VII. Findings and Current Challenges
The current challenges relating to the aggregation of electricity supply plans are as follows.
i. Toward the security of stable supply until the functioning of the capacity market
The following conditions were recognized at the previous year’s aggregation of the plans: a) former
general electric utilities will decrease their supply capacity according to the decrease in theircustomers; b) small-to-medium-sized retail companies will grab market share without procuring
their supply capacity, which will remain “unspecified procurement.” Both conditions lead to declining
reserve margins in regional service areas and this tendency is likely to continue. At the current
aggregation, the Organization has again recognized this tendency.
In addition, the following new tendencies or conditions are recognized at the current aggregation.
Movement toward increasing supply capacity• The Organization requested the cooperation of all electric power companies in securing supply
capacity, and made individual requests to major electric power companies and solicited their
feedback. As a result, the maintenance work schedule of planned outages of generators wascoordinated to avoid summer or winter peak periods. However, based on the actual condition s or
feedback from the electric power companies, it cannot be expected that greater coordination of themaintenance work schedule will occur in the future simply by request from the Organization due toconstraints of workers and economic reasons.
• Moves were made to ensure a balance of supply and demand, such as canceling discontinuanceplans of generators, taking into account supply–demand conditions during the severe cold of theprevious winter in 50 Hz areas.
Movement toward decreasing supply capacity• The demand forecasts of retail or generation departments of former general electric utilities
indicate a significant loss in their shares in their own regional service areas, and they plan theirgenerators anew based on their demand forecasts. They intend to actively utilize an electronicbulletin board system for information on generating facilities (launched by the Organization in April2019) before the stage of deciding on generator discontinuance plans in their companies, thereby
maintaining the generators in a rapid power-generatable mode in anticipation of launching thecapacity market.
• Under the condition that competition between retail departments of former electric utilities
becomes fierce, such retail companies (including companies consisting of those majorly funded byformer electric utilities) will indicate the tendency of their supply capacity as “unspecified
procurement,” as is the case with other PPSs in external areas other than in their own service areas.
Given the tendencies stated above, the Organization has aggregated the supply–demand balance ofelectric supply plans for FY 2019, and reached the projection that the adequate reserve margin of
8% will be secured in the supply–demand balance with the utilization of cross-regional
interconnection lines in both the short- and the mid-to-long term.
51

From the perspective of enhancing the resilience of the electric power grid, there are discussions on
the necessary reserve capacity against severe weather or rare occurrence risk, and on the evaluation
method for calculating renewable energy generation (kW value). The Organization recognizes thatthe necessary supply capacity will be secured if maintenance work schedules are adequately
coordinated and discontinued generators are effectively utilized.
However, it cannot be denied that more generators will be discontinued or retired until FY 2024
when supply capacity is secured in the capacity market. If retail companies are projected to fail tosecure the necessary supply capacity, GT&D companies independently have to secure supply
capacity as an unavoidable response during the transition period.
The Organization will review the details of the supply capacity-securing scheme including therequirement for generators to clearly and flexibly implement securing supply capacity measures such as
coordination of maintenance work schedules of generators, delayed discontinuance of generators, or
restoring generators with appropriate timing. The Organization recommends the Government toexamine institutional measures including cost allocation and the accompanying security of generators.
In parallel with the above-stated actions and the circumstances outlined in which it is crucial tofinely and successively perceive the security of supply capacity in the future, the Organization will
focus on the apprehension of discontinuance or retirement of generators in advance, and explore
measures such as the utilization of an electronic bulletin board system for information on generating
facilities, which aims at effective utilization of generators to be discontinued or retired.
<Reference 1> Review by the National Council

Source: Documents from the 29th task forth meeting of the Strategic Policy Subcommittee,
Electricity and Gas Industry Committee, Advisory Committee for Natural Resources and Energy(February 28, 2019)

The original document [only in Japanese] is available athttps://www.meti.go.jp/shingikai/enecho/denryoku_gas/denryoku_gas/seido_kento/pdf/029_03_01.pdf
52

ii. Ideal electricity supply plan after the launch of the capacity market
Currently, supply capacity has been reviewed with respect to whether the necessary capacity issecured in the electricity supply plan. At the same time, a detailed review has been undertaken forthe launch of the capacity market, after which the necessary supply capacity will be secured in themarket scheme. Increased implementation of securing the supply capacity under the tendency that
supply capacity is defined as “unspecified procurement” or “generation without sales destination” isvital.
Regarding the electricity supply plan after the launch of the capacity market, there will be an overlap
with the capacity market in terms of aims and roles; these will be distinguished from the current planfor contents and items required for each business license (retail companies, generation companies, andGT&D companies). Therefore, the electricity supply plan will be changed to become a more efficientand effective scheme in the future by clarifying the aims and roles of each business license.
The Organization will review the information to be collected and the aims of the electricity supply
plan in anticipation of review of the imbalance tariff system examined by the National Council, suchas the Strategic Policy Subcommittee of the Advisory Committee for Natural Resources and Energy,
and the Meeting for System Design of Electricity and Gas Market Surveillance Commission, and thebalancing capacity market after outlining the information to be secured in the capacity market
scheme. The Organization recommends the Government to proceed to examine the ideal electricity
supply plan after launching the capacity market in cooperation with the Organization.
<Reference 2> Supply capacity procured in the capacity market

Source: Documents from the Capacity Market Orientation Meeting in March 2019

The original document [only in Japanese] is available at

http://www.occto.or.jp/kaiin/oshirase/files/youryou_setsumei0311.pdf
53

iii. Balancing capacity toward strengthening resilience of the power grid under the g reaterin tegration of renewable energy g eneration
With publication of the interim report of the Working Group on Electricity Resilience, theOrganization continues to review the subject scope of supply capacity in the capacity market toinclude measures against severe weather or rare occurrence risk; these stand in aspect of adequacy(necessary capacity) of the supply capacity.
Regarding the events that might have led to a power shortage in the Chubu EPCO area due to output
decrease of solar power in cloudy weather and demand increase in severe cold in January 2019, it issuggested that maintaining the supply–demand balance requires not only ensuring sufficient supply
adequacy but also securing and operating the balancing capacity.
In relation to the abovementioned events, the ideal balancing capacity has been currently reviewed
by the Subcommittee on Greater Introduction of Renewable Energy and Advanced Electric Network;balancing capacity will be secured by changing the procurement of Generator I’ to year-round
operation for the time being. Beyond launching the balancing market, the balancing capacity will be
secured by procuring delta kW of Replacement Reserve for FIT and to be operated.
The Organization will proceed to review the ideal balancing capacity and its operation toward
launching the balancing market in anticipation of greater integration of renewable energy
generation. The Organization recommends the Government to examine a detailed system design
such as an imbalance tariff system or cost allocation method.

54

<Reference 3> Supply–demand state in the Chubu EPCO area on January 10, 2019

<Reference 4> Supply–demand state in the Chubu EPCO area on January 10, 2019

Source of References 3 and 4:Document 2-1 from the 36th Meeting of the Study Committee on
Regulating and Marginal Supply Capability and Long-Term Supply–Demand Balance Evaluation(February 19, 2019)

The original document [only in Japanese] is available athttps://www.occto.or.jp/iinkai/chouseiryoku/2018/files/chousei_jukyu_36_02_01.pdf

55

<Reference 5> Review by the National Council

Source: Document 4 from the 11th Meeting of the Subcommittee on Greater Introduction of
Renewable Energy and Advanced Electric Network, Committee on Energy Efficiency and Renewable
Energy/ Electricity and Gas Industry Committee, Advisory Committee for Natural Resources andEnergy (December 16, 2018)

The original document [only in Japanese] is available athttps://www.meti.go.jp/shingikai/enecho/denryoku_gas/saisei_kano/pdf/011_04_00.pdf<Reference 6> Review by the National Council

Source: The Second Interim Report of the Subcommittee on Greater Introduction of Renewable
Energy and Advanced Electric Network Committee on Energy Efficiency and Renewable Energy/
Electricity and Gas Industry Committee, Advisory Committee for Natural Resources and Energy(January 28, 2019)

The original document [only in Japanese] is available athttps://www.meti.go.jp/shingikai/enecho/denryoku_gas/saisei_kano/pdf/20190128001_01.pdf
56

VIII. Conclusions
1. Electricity Demand Forecast
The AAGRs of both peak demand nationwide (average of the three highest daily loads) and electricenergy requirement nationwide in the mid-to-long term are forecast to decrease by 0.1%.

AAGRs

have become negative, and this is attributable to a number of major factors, such as efforts to reduce
electricity use, wider utilization of energy-saving electric appliances, a shrinking population, andload-levelling measures.
2. Electricity Supply and Demand
Regarding the supply–demand balance evaluation in each regional service area during the 10-year
period, the criterion of a stable supply, i.e., a reserve margin of 8% (supply capacity over peakdemand by deducting the capacity of the largest generating unit and balancing capacity withfrequency control [Generator I] in Okinawa) is projected to be secured in all areas and years by
sharing power from other areas with sufficient supply capacity through cross-regional
interconnection lines. The Organization will continuously and carefully evaluate the supply–demandbalance, by monitoring the submission of changing supply plans and the accompanying supply–
demand balance.
3. Analysis of the Transition of Power Generation Sources Nationwide
Regarding the transitions of installed power generation capacity and gross electricity generation,
renewable energy such as solar power is projected to increase greatly; at the same time, coal and
LNG will increase their capacity but remain the same or decrease in terms of energy generation. For
nuclear power plants, energy generations calculated as zero for their capacity is reported as“uncertain”.
4. Development Plans for Transmission and Distribution Facilities
Regarding the development plans for major transmission lines or substations, there are no changes
for cross-regional interconnection lines from the previous year’s plans.
5. Cross-Regional Operation
For procuring supply capacity or energy from the external service areas, aggregated results arealmost the same in both the areas with higher procurement from the external service areas and in
the areas with higher transmission to the external areas.
6. Analysis of Characteristics of Electric Power Companies
Distributions are calculated for retail companies and generation companies according to businessscale and business areas, and aggregated to the projection during the 10-year period. In addition,
the ratios of the secured supply capacity are reviewed. In particular, small-to-medium-sized retailcompanies have planned their supply capacity as “unspecified procurement,” as in the previous
57year’s plan. As a result, the ratios of the secured supply capacity indicate declining tendency.
7. Findings and Challenges
The Organization has communicated its opinions to the Minister of Economy, Trade and Industry
concerning three major challenges relating to electricity supply plans, the ideal evaluation method
for the supply–demand balance, and current challenges in the electricity business in relation to theaggregation of electricity supply plans for FY 2019.

Attached are the Appendices on the aggregation of the electricity supply plans.

APPENDIX 1 Supply–Demand Balance for FY 2019・・・・・・・・・・・・・・・・・・・ A1
APPENDIX 2 Long-Term Supply–Demand Balance for the 10-year Period FY 2019–2028・・・ A3

58

APPENDIX 1 Supply–Demand Balance for FY 2019
Tables A1-1 to A1-4 show the monthly peak demand, monthly supply capacity, monthly reserve
capacity, and reserve margin for each regional service area in FY 2019, respectively. Table A1-5
shows the monthly projection of the reserve margin for each regional service area recalculated withpower exchanges to areas below the 8% reserve margin from areas with over 8% reserve margin.
Table A1-1 Monthly Peak Demand Forecast for Each Regional Service Area
[104kW]

Apr.
403
1,060
3,848

May
369
975
3,649

Jun.
365
1,047
4,081

Jul.
407
1,262
5,311

Aug.
420
1,270
5,311

Sep.
401
1,145
4,512

Oct.
415
1,067
3,695

Nov.
456
1,187
4,026

Dec.
486
1,312
4,382

Jan.
499
1,375
4,698

Feb.
493
1,360
4,698

Mar.
459
1,268
4,312

50 Hz area
Total

5,311

4,993

5,493

6,980

7,001

6,058

5,177

5,669

6,180

6,572

6,551

6,039

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

1,837
373
1,847
756
350
1,044

1,905
372
1,842
757
355
1,044

2,056
410
2,141
842
402
1,157

2,416
495
2,607
1,028
503
1,484

2,416
495
2,607
1,028
503
1,482

2,188
458
2,308
911
441
1,320

1,961
373
1,913
779
364
1,162

1,964
424
1,993
837
375
1,179

2,215
476
2,367
998
464
1,486

2,311
499
2,420
1,016
464
1,506

2,311
499
2,420
1,016
464
1,506

2,149
471
2,176
909
414
1,281

60 Hz area
Total
Interconnected

6,207

6,274

7,008

8,533

8,531

7,625

6,551

6,772

8,006

8,216

8,216

7,400

Hokkaido
TohokuTokyo

11,518 11,267 12,501 15,513 15,532 13,683 11,728 12,441 14,186 14,788 14,767 13,439
Okinawa
104
121
139
148
148
143
132
112
99
104
103
97
Nationwide 11,623 11,389 12,640 15,661 15,680 13,826 11,861 12,552 14,285 14,892 14,870 13,536

Table A1-2 Monthly Projection of Supply Capacity for Each Regional Service Area
[104kW]

Apr.
549
1,270
4,624

May
544
1,236
4,773

Jun.
573
1,224
4,846

Jul.
493
1,443
5,761

Aug.
513
1,416
5,773

Sep.
501
1,294
5,531

Oct.
497
1,171
4,574

Nov.
545
1,330
4,692

Dec.
608
1,460
5,260

Jan.
597
1,525
5,561

Feb.
599
1,523
5,481

Mar.
568
1,425
5,336

50 Hz area
Total

6,442

6,553

6,643

7,697

7,702

7,326

6,243

6,566

7,327

7,683

7,603

7,329

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

2,332
478
2,412
938
500
1,415

2,306
461
2,308
923
497
1,315

2,461
471
2,441
984
523
1,304

2,618
575
2,778
1,157
605
1,627

2,660
550
2,751
1,143
584
1,553

2,577
529
2,678
1,045
507
1,443

2,335
422
2,293
929
450
1,351

2,301
458
2,390
942
472
1,366

2,409
541
2,573
1,004
537
1,566

2,545
546
2,706
1,102
483
1,650

2,584
545
2,673
1,116
489
1,644

2,527
547
2,553
1,060
424
1,610

60 Hz area
Total
Interconnected

8,075

7,809

8,184

9,359

9,241

8,778

7,781

7,930

8,631

9,033

9,049

8,719

Hokkaido
TohokuTokyo

14,517 14,362 14,827 17,056 16,944 16,105 14,023 14,496 15,958 16,716 16,652 16,049
Okinawa
162
172
188
197
197
198
194
172
172
177
184
179
Nationwide 14,679 14,535 15,016 17,253 17,141 16,303 14,218 14,668 16,130 16,893 16,836 16,228

59

Table A1-3 Monthly Projection of Reserve Capacity for Each Regional Service Area
[104kW]

Apr.
146
210
776

May
175
261
1,124

Jun.
208
177
765

Jul.
86
181
450

Aug.
93
146
462

Sep.
100
150
1,019

Oct.
82
104
879

Nov.
89
143
666

Dec.
122
148
878

Jan.
98
150
863

Feb.
106
163
783

Mar.
109
157
1,024

50 Hz area
Total

1,131

1,560

1,150

717

701

1,269

1,066

897

1,147

1,111

1,052

1,290

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

495
105
565
182
150
371

401
89
466
166
142
271

405
61
300
142
121
147

202
79
170
129
102
142

244
55
144
115
81
72

389
71
370
134
66
123

374
50
380
150
86
189

337
34
397
105
97
187

194
65
206
6
73
80

234
47
286
86
19
144

273
46
253
100
25
138

378
76
377
151
10
329

60 Hz area
Total
Interconnected

1,867

1,535

1,176

826

710

1,153

1,229

1,158

625

817

833

1,320

2,998
58
3,056

3,095
51
3,146

2,326
50
2,376

1,543
49
1,592

1,411
50
1,461

2,422
55
2,477

2,295
62
2,357

2,056
60
2,116

1,772
73
1,846

1,928
73
2,001

1,885
80
1,966

2,610
82
2,692

Hokkaido
TohokuTokyo

Okinawa
Nationwide

Table A1-4 Monthly Projection of Reserve Margin for Each Regional Service Area
(resources within own service area only, at the sending end; see Table 2-3)
Hokkaido
Tohoku
Tokyo

Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
36.2% 47.4% 57.0% 21.1% 22.2% 24.9% 19.7% 19.5% 25.0% 19.6% 21.5% 23.8%
19.8% 26.8% 16.9% 14.3% 11.5% 13.1% 9.8% 12.0% 11.3% 10.9% 12.0% 12.4%
20.2% 30.8% 18.7% 8.5% 8.7% 22.6% 23.8% 16.5% 20.0% 18.4% 16.7% 23.8%

50 Hz area
Total

21.3% 31.2% 20.9% 10.3% 10.0% 20.9% 20.6% 15.8% 18.6% 16.9% 16.1% 21.4%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

26.9%
28.1%
30.6%
24.1%
42.9%
35.5%

60 Hz area
Total
Interconnected30.1% 24.5% 16.8%

21.1%
24.0%
25.3%
21.9%
39.9%
26.0%

19.7% 8.4% 10.1% 17.8% 19.0%
15.0% 16.1% 11.0% 15.6% 13.3%
14.0% 6.5% 5.5% 16.0% 19.9%
16.8% 12.6% 11.2% 14.8% 19.3%
30.1% 20.2% 16.1% 14.9% 23.8%
12.7% 9.6% 4.8% 9.3% 16.3%
9.7%

17.2% 8.7% 10.1% 11.8% 17.6%
8.1% 13.7% 9.4% 9.3% 16.2%
19.9% 8.7% 11.8% 10.4% 17.3%
12.6% 0.6% 8.4% 9.8% 16.6%
26.0% 15.8% 4.2% 5.3% 2.4%
15.9% 5.4% 9.6% 9.1% 25.7%

8.3% 15.1% 18.8% 17.1%

7.8%

9.9% 10.1% 17.8%

26.0% 27.5% 18.6% 9.9% 9.1% 17.7% 19.6% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 41.9% 35.7% 33.1% 33.5% 38.1% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.6% 18.8% 10.2% 9.3% 17.9% 19.9% 16.9% 12.9% 13.4% 13.2% 19.9%
Below Criteria of 8%

Table A1-5 Monthly Projection of Reserve Margin for Each Regional Service Area
(with power exchange through cross-regional interconnection lines, at the sending end; s ee Table 2-4)
Apr.
May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
21.3% 29.8% 45.2% 11.3% 12.4% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 22.3%
21.3% 28.9% 17.8% 11.3% 9.0% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 19.3%
21.3% 28.9% 17.8% 9.8% 9.0% 19.2% 19.6% 16.0% 16.9% 15.4% 14.6% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.8% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.3%
30.1% 26.3% 17.8% 9.8% 9.0% 16.4% 19.6% 17.0% 9.1% 11.1% 11.3% 19.5%
Interconnected 26.0% 27.5% 18.6%
9.9% 9.1% 17.7% 19.6% 16.5% 12.5% 13.0% 12.8% 19.4%
Okinawa 55.3% 41.9% 35.7% 33.1% 33.5% 38.1% 46.9% 53.9% 73.8% 70.3% 78.0% 84.3%
Nationwide 26.3% 27.6% 18.8% 10.2% 9.3% 17.9% 19.9% 16.9% 12.9% 13.4% 13.2% 19.9%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved to over 8%

A260

APPENDIX 2 Long-Term Supply–Demand Balance for the 10-year Period FY 2019–2028
Tables A2-1 to A2-4 show a 10-year projection of the annual peak demand, annual supply capacity,
annual reserve capacity, and reserve margin for each regional service area from FY 2019 to FY 2028,
respectively. Table A2-5 shows the annual projection of the reserve margin for each regional service
area recalculated with power exchanges from areas with over 8% reserve margin to areas below the
8% reserve margin. Tables A2-6 to A2-9 show a 10-year projection of the annual peak demand,
annual supply capacity, annual reserve capacity, and reserve margin for winter peak areas of
Hokkaido and Tohoku, respectively.

Table A2-1 Annual Peak Demand Forecast for Each Regional Service Area (at 17:00 in August)[104kW]

2019
420
1,270
5,132

2020
420
1,268
5,109

2021
419
1,267
5,112

2022
419
1,263
5,115

2023
419
1,259
5,118

2024
418
1,254
5,122

2025
418
1,249
5,127

2026
418
1,244
5,131

2027
418
1,239
5,148

2028
418
1,234
5,152

50 Hz area
Total

6,822

6,797

6,798

6,797

6,796

6,794

6,794

6,793

6,805

6,804

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

2,416
495
2,607
1,028
496
1,544

2,419
495
2,597
1,030
495
1,544

2,407
495
2,588
1,029
494
1,544

2,397
495
2,581
1,027
492
1,544

2,386
495
2,574
1,025
491
1,545

2,375
495
2,567
1,024
490
1,545

2,365
494
2,560
1,022
488
1,546

2,354
494
2,552
1,020
487
1,546

2,357
494
2,545
1,019
486
1,547

2,346
494
2,538
1,017
485
1,547

60 Hz area
Total
Interconnected

8,586

8,579

8,556

8,536

8,516

8,496

8,475

8,453

8,448

8,427

Hokkaido
TohokuTokyo

15,408 15,377 15,354 15,332 15,312 15,289 15,269 15,246 15,253 15,231
Okinawa
148
149
150
150
151
152
152
153
153
154
Nationwide 15,556 15,526 15,504 15,483 15,463 15,441 15,421 15,399 15,406 15,385

Table A2-2 Annual Projection of Supply Capacity for Each Regional Service Area (at 17:00 in August)[104kW]

2019
513
1,416
5,594

2020
509
1,379
5,743

2021
573
1,500
5,614

2022
576
1,515
5,452

2023
580
1,514
5,623

2024
581
1,521
5,740

2025
582
1,521
5,975

2026
580
1,549
5,940

2027
627
1,550
5,944

2028
627
1,551
5,951

50 Hz area
Total

7,523

7,631

7,688

7,543

7,717

7,842

8,077

8,069

8,121

8,129

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

2,660
550
2,751
1,143
576
1,684

2,642
553
2,895
1,196
645
1,801

2,432
545
2,674
1,227
561
1,783

2,498
544
2,700
1,140
549
1,799

2,501
544
2,756
1,175
595
1,813

2,504
543
2,759
1,177
594
1,733

2,496
537
2,646
1,181
594
1,734

2,501
536
2,662
1,183
595
1,715

2,503
535
2,663
1,180
595
1,718

2,503
535
2,663
1,181
595
1,718

60 Hz area
Total
Interconnected

9,364

9,732

9,222

9,229

9,384

9,310

9,189

9,193

9,195

9,194

Hokkaido
TohokuTokyo

16,887 17,364 16,910 16,772 17,102 17,151 17,266 17,262 17,316 17,323
Okinawa
201
211
204
208
202
214
214
214
214
214
Nationwide 17,088 17,575 17,113 16,980 17,303 17,365 17,480 17,476 17,530 17,537

61
A3

Table A2-3 Annual Projection of Reserve Capacity for Each Regional Service Area (at 17:00 in August)[104kW]

2019
93
146
462

2020
89
111
634

2021
154
234
502

2022
157
253
337

2023
161
256
505

2024
163
267
618

2025
164
272
848

2026
162
305
809

2027
209
311
796

2028
209
317
799

50 Hz area
Total

701

834

890

746

922

1,048

1,284

1,276

1,316

1,325

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

244
55
144
115
80
140

223
58
298
166
150
258

25
50
85
198
67
240

101
49
119
113
57
255

115
49
182
150
104
268

129
48
192
153
104
188

131
44
86
159
106
188

147
43
110
163
108
169

146
42
119
161
109
170

157
41
125
164
110
170

778

1,153

666

693

868

814

714

740

747

767

1,479
53
1,532

1,987
63
2,050

1,556
54
1,610

1,440
58
1,498

1,790
51
1,841

1,862
62
1,924

1,997
62
2,059

2,016
61
2,077

2,063
61
2,123

2,092
60
2,152

Hokkaido
TohokuTokyo

60 Hz area
Total
Interconnected

Okinawa
Nationwide

Table A2-4 Annual Projection of Reserve Margin for Each Regional Service Area
(resource within own service area only, at 17:00 in August, at the sending end; s ee Table 2-8)
Hokkaido
Tohoku
Tokyo

2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
22.2% 21.3% 36.8% 37.4% 38.5% 39.0% 39.3% 38.7% 50.0% 50.1%
11.5%
8.7% 18.5% 20.0% 20.3% 21.3% 21.8% 24.6% 25.1% 25.7%
9.0% 12.4%
9.8%
6.6%
9.9% 12.1% 16.5% 15.8% 15.5% 15.5%

50 Hz area
Total

10.3% 12.3% 13.1% 11.0% 13.6% 15.4% 18.9% 18.8% 19.3% 19.5%

Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu

10.1%
11.0%
5.5%
11.2%
16.1%
9.1%

60 Hz area
Total
Interconnected

9.2%
11.7%
11.5%
16.2%
30.2%
16.7%

9.1% 13.4%

1.0%
4.2%
4.8%
5.4%
5.6%
6.3%
6.2%
6.7%
10.2%
9.9%
9.9%
9.8%
8.8%
8.6%
8.4%
8.3%
3.3%
4.6%
7.1%
7.5%
3.4%
4.3%
4.7%
4.9%
19.3% 11.0% 14.6% 15.0% 15.6% 16.0% 15.8% 16.1%
13.6% 11.5% 21.2% 21.2% 21.7% 22.1% 22.5% 22.8%
15.5% 16.5% 17.3% 12.1% 12.1% 10.9% 11.0% 11.0%
7.8%

8.1% 10.2%

9.6%

8.4%

8.7%

8.8%

9.1%

9.6% 12.9% 10.1%
9.4% 11.7% 12.2% 13.1% 13.2% 13.5% 13.7%
Okinawa
35.7% 42.1% 36.1% 38.5% 33.9% 41.1% 40.7% 40.0% 39.5% 39.0%
Nationwide
9.8% 13.2% 10.4%
9.7% 11.9% 12.5% 13.4% 13.5% 13.8% 14.0%
Below Criteria of 8%

62
A4

Table A2-5 Annual Projection of Reserve Margin for Each Regional Service Area
(with power exchanges through cross-regional interconnection lines, at the sending end; s ee Table 2-8)
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
12.4% 12.3% 27.6% 27.2% 28.3% 28.8% 29.0% 29.0% 40.4% 40.4%
9.5% 12.3% 9.6% 8.7% 11.2% 11.7% 14.6% 14.8% 14.6% 13.2%
9.5% 12.3% 9.6% 8.7% 11.2% 11.7% 14.6% 14.8% 14.6% 13.2%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.6% 8.7% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
9.5% 13.4% 9.9% 10.5% 11.2% 11.7% 11.1% 11.3% 11.4% 12.8%
Interconnected
9.6% 12.9% 10.1% 9.4% 11.7% 12.2% 13.1% 13.2% 13.5% 13.7%
Okinawa 35.7% 42.1% 36.1% 38.5% 33.9% 41.1% 40.7% 40.0% 39.5% 39.0%
Nationwide 9.8% 13.2% 10.4% 9.7% 11.9% 12.5% 13.4% 13.5% 13.8% 14.0%
Hokkaido
TohokuTokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
KyushuImproved to over 8%

Table A2-6 Annual Peak Demand Forecast for Winter Peak Areas of Hokkaido and Tohoku (at 18:00 in January)[104kW]

Hokkaido
Tohoku2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
499
499
498
498
497
497
497
496
496
496
1,375 1,373 1,371 1,368 1,364 1,360 1,356 1,352 1,348 1,344

Table A2-7 Annual Projection of Supply Capacity for Winter Peak Areas of Hokkaido and Tohoku (at 18:00 in January)[104kW]

Hokkaido
Tohoku2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
597
599
571
580
580
581
582
631
631
631
1,525 1,508 1,524 1,539 1,538 1,541 1,542 1,568 1,571 1,572

Table A2-8 Annual Projection of Reserve Capacity for Winter Peak areas of Hokkaido and Tohoku (at 18:00 in January)[104kW]

Hokkaido
Tohoku2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
98
100
73
82
83
84
85
135
135
135
150
135
153
171
174
181
186
216
223
228

Table A2-9 Annual Projection of Reserve Margin for Winter Peak Areas of Hokkaido and Tohoku(at 18:00 in January; s ee Table 2-10)
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Hokkaido 19.6% 20.1% 14.7% 16.5% 16.8% 17.0% 17.1% 27.2% 27.2% 27.2%
Tohoku10.9% 9.8% 11.2% 12.5% 12.8% 13.3% 13.7% 16.0% 16.5% 16.9%

A563