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M. Chen et al.
(2) Initial cost:
a. Introduction cost as the product of unit price and each technology’s capacity.
b. Annual Introduction cost is introduction cost divided by lifetime (measured
in years).
c. Initial costs are the total sum of each technology’s annual introduction cost.
(3) Running cost:
a. Annual power consumption from the operation of the technology system
determined by the capacity of each technology.
b. Running cost is the product power purchase price and annual power
consumption.
Technical parameters including unit price, lifetime, efficiency, etc. of each technology were set as shown in Table 41.1. In order to carry out the analysis while taking
into consideration the future performance improvement of each technology, we estimated what each technology’s performance in 2030 would be based on various references [Japan Science and Technology Agency Center low carbon society strategy
(2016, 2017); Fuel Cells and Hydrogen Joint Undertaking (2014); Keizai (2017);
International Energy Agency (2015); United States Department of Energy (2009);
Tokyo Electric Power Company (2009)]. In this estimation, cost reduction by technological progress and learning by doing are taken into consideration. It is assumed
that PV is a single crystal silicon type, EC is an alkali type, FC is a solid oxide type,
and the hydrogen tank can handle 40 MPa compressed hydrogen.
41.4.2 Result
To clarify the cost composition of this model, we calculated total and detailed cost
for 5 different patterns. Figure 41.6 shows the total cost and its breakdown in five
different scenarios including 10JPY, 20JPY, and 30JPY in power grid price (Grid in
grey bar graph), and Non-H2. The horizontal axis represents each scenario’s relative
cost to Grid (set at 1.0 wherein all electricity demand is satisfied by grid power).
This is followed by the Non-H2 case (using PV power generation without storing
surplus power) and then the selling power cases where demand is fixed regardless of
the selling price (with selling power to the grid priced at 10JPY, 20JPY, and 30JPY,
while purchasing power from the grid priced at a fixed in 21JPY). The bars in the
graph represent relative cost for values >0, and amount sold for values <0. The red
dotted line represents total cost, defined as annual system cost minus power selling
revenue.
Comparing the scenarios of the selling prices of 20 JPY and 30 JPY with the
case of Non-H2, the total cost is lower in the 20 JPY and 30 JPY scenarios. In these
scenarios, although the technology system cost is high, the selling income is also
high, in particular, power sold from FC accounted for the majority of the revenue.
M. Chen et al.
(2) Initial cost:
a. Introduction cost as the product of unit price and each technology’s capacity.
b. Annual Introduction cost is introduction cost divided by lifetime (measured
in years).
c. Initial costs are the total sum of each technology’s annual introduction cost.
(3) Running cost:
a. Annual power consumption from the operation of the technology system
determined by the capacity of each technology.
b. Running cost is the product power purchase price and annual power
consumption.
Technical parameters including unit price, lifetime, efficiency, etc. of each technology were set as shown in Table 41.1. In order to carry out the analysis while taking
into consideration the future performance improvement of each technology, we estimated what each technology’s performance in 2030 would be based on various references [Japan Science and Technology Agency Center low carbon society strategy
(2016, 2017); Fuel Cells and Hydrogen Joint Undertaking (2014); Keizai (2017);
International Energy Agency (2015); United States Department of Energy (2009);
Tokyo Electric Power Company (2009)]. In this estimation, cost reduction by technological progress and learning by doing are taken into consideration. It is assumed
that PV is a single crystal silicon type, EC is an alkali type, FC is a solid oxide type,
and the hydrogen tank can handle 40 MPa compressed hydrogen.
41.4.2 Result
To clarify the cost composition of this model, we calculated total and detailed cost
for 5 different patterns. Figure 41.6 shows the total cost and its breakdown in five
different scenarios including 10JPY, 20JPY, and 30JPY in power grid price (Grid in
grey bar graph), and Non-H2. The horizontal axis represents each scenario’s relative
cost to Grid (set at 1.0 wherein all electricity demand is satisfied by grid power).
This is followed by the Non-H2 case (using PV power generation without storing
surplus power) and then the selling power cases where demand is fixed regardless of
the selling price (with selling power to the grid priced at 10JPY, 20JPY, and 30JPY,
while purchasing power from the grid priced at a fixed in 21JPY). The bars in the
graph represent relative cost for values >0, and amount sold for values <0. The red
dotted line represents total cost, defined as annual system cost minus power selling
revenue.
Comparing the scenarios of the selling prices of 20 JPY and 30 JPY with the
case of Non-H2, the total cost is lower in the 20 JPY and 30 JPY scenarios. In these
scenarios, although the technology system cost is high, the selling income is also
high, in particular, power sold from FC accounted for the majority of the revenue.