1
Revised Analysis of the Cost per Kilowatt Hour
to Store Electricity
Haneen Aburub, and Ward T. Jewell, Fellow, IEEE

Abstract—This paper revises the costs previously determined
for using various grid-connected electric energy storage
technologies. Life-cycle cost analysis technique [1] is used. The
results present the cost added to electricity stored and discharged,
in US$/kWh.
Index Terms — Batteries, economic analysis, energy storage
I. INTRODUCTION
T
HERE are many benefits that electric energy storage
systems can provide to enhance the current electric grid
such as providing ancillary services and increasing the
penetration level of renewable resources. However, 95% of the
current storage capacity is pumped hydro due its low cost [2].
New pumped hydro installations are limited with the site
requirements and environmental impacts. Thus, the major
driving factor of how much other storage technologies such as
batteries and compressed air energy storage CAES are adopted
in electricity grid, is the economy.
This paper applies a life cycle cost analysis technique [1] to
revise the costs previously determined for electric energy
storage systems. The results present the cost added to each unit
of electric energy stored in US$/kWh. These results are used
to evaluate the economic feasibility of the storage systems by
comparing them with the existing electricity prices and
previous economic analysis results. Conclusions are then
presented based on the results.
II. CASE STUDIES
A. Assumptions
In the case studies presented in this section, systems are
assumed to operate either 250 or 100 days/yr. The
approximate number of weekdays minus holidays in a year is
250. so this represents daily use. Peak summer seasons are
approximated to be 100 days per year, so this represents daily
use during the peak season.
The length and frequency of charge/discharge cycle depends
on the application. For generation storage systems, the length
of discharge cycle is assumed to be 8h [1]. The storage for
generation is designed to charge overnight and discharge
during the day [1]. Thus, the generation storage systems are
charged and discharged one time during each day [1]. For
The authors are with the Wichita State University, Wichita, KS 67260
USA (e-mail: hxaburub@wichita.edu; ward.jewell@wichita.edu)
T&D storage systems, the length of the discharge cycle is
assumed to be 4h [1]. The storage for T&D is designed to
discharge during morning and afternoon periods and is
charged at other times [1]. Thus, T&D storage systems are
charged and discharged twice during each day [1].
The designed rated output capacity for generation storage
systems is 10 MW, and 2.5 MW for T&D storage systems [1].
The annual interest rate for financing the storage system is
assumed to be 7.7% [1]. Inflation and escalation rates are not
considered in this analysis [1].
The unit cost for power electronics is assumed to be 1.25
times the power conversion system equipment cost for
generation and T&D applications [3].
The unit cost for balance of plant is assumed to be equal to
the utility interconnection cost [3].
The fixed operation and maintenance costs are assumed to
be 2% of the unit cost for power electronics [3].
Due to a lack of available manufacturers’ data, the life of
storage is assumed to be equal to the calculated replacement
period.
The future amount of replacement cost is assumed to be
30% of the unit cost for storage unit [3].
B. Storage Systems and Technologies
Both commercial battery technologies and those still in
development are considered for generation and T&D
application: lithium ion (Li-ion), advanced lead acid (Adv.
LA), vanadium redox (VB), sodium sulfur (Na/S), zinc
bromine (Zn/Br), iron chromium (Fe/Cr), zinc air (Zn/Air),
zinc halogen (Zn/H). The commercial and near-commercial
non-battery storage technologies are compressed air (CAES)
and pumped hydro (PH). CAES is considered for both
generation and T&D applications, whereas pumped hydro is
considered for generation applications only.
Manufactures of these storage technologies provided prices
and performance information in 2011 and 2012. These prices
are presented in Tables I, II, III, and IV. The data for
generation applications are shown in Tables I and II. For T&D
applications, the data are shown in Tables III and IV.
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TABLE I
REVISED CASE VALUES FOR GENERATION APPLICATIONS [3], [4], [7]
TABLE III
REVISED CASE VALUES FOR T&D APPLICATIONS [3], [4], [7]
Parameter
Li-ion
Adv.
LA
Zn/Br
Na/S
VB
Parameter
Li-ion
Adv.
LA
Zn/Br
Na/S
VB
Rated output (MW)
10
10
10
10
10
Rated output (MW)
2.5
2.5
2.5
2.5
2.5
Efficiency
0.9
0.8
0.6
0.77
0.75
Efficiency
0.9
0.8
0.6
0.77
0.75
Unit cost for power
electronic (US$/kW)
375
375
375
375
375
Unit cost for power
electronic (US$/kW)
312.5
312.5
312.5
312.5
312.5
2375
1300
490
900
1000
500
350
400
750
Unit cost for storage units
(US$/kWh)
2400
Unit cost for storage
units (US$/kWh)
23
23
23
23
7
7
7
7
7
Unit cost for balance of
plant (US$/kWh)
23
Unit cost for
balance of plant
(US$/kWh)
Fixed O&M cost
(US$/kW)
7.5
7.5
7.5
7.5
6.26
6.26
6.26
6.26
Fixed O&M cost
(US$/kW)
7.5
6.26
712.5
390
147
270
300
150
105
120
225
8000
2000
1500
4500
100000
8000
2000
3000
4500
100000
Future amount of
replacement cost
(US$/kWh)
Number of charge/
discharge cycles in life
720
Future amount of
replacement cost
(US$/kWh)
Number of
charge/discharge
cycles in life
TABLE II
REVISED CASE VALUES FOR GENERATION APPLICATIONS [3], [4], [7]
Parameter
Fe/Cr
Zn/Air
Zn/H
CAES
PH
Rated output (MW)
Efficiency
Unit cost for power
electronic (US$/kW)
Unit cost for storage
units (US$/kWh)
Unit cost for balance
of plant (US$/kWh)
Fixed O&M cost
(US$/kW)
Future amount of
replacement cost
(US$/kWh)
Number of charge/
discharge cycles in
life
10
0.7
312.5
10
0.7
312.5
10
0.75
312.5
10
0.9
312.5
10
0.85
312.5
350
300
640
500
300
7
7
7
7
7
6.26
6.26
6.26
6.26
6.26
105
90
192
150
90
3750
3750
3750
12500
6250
TABLE IV
REVISED CASE VALUES FOR T&D APPLICATIONS [3], [4], [7]
Parameter
Fe/Cr
Zn/Air
Zn/H
CAES
Rated output (MW)
Efficiency
Unit cost for power electronic
(US$/kW)
Unit cost for storage units
(US$/kWh)
Unit cost for balance of plant
(US$/kWh)
Fixed O&M cost (US$/kW)
Future amount of replacement
cost (US$/kWh)
Number of charge/
discharge cycles in life
2.5
0.7
375
2.5
0.7
375
2.5
0.75
375
2.5
0.9
375
400
350
750
600
23
23
23
23
7.5
120
7.5
105
7.5
225
7.5
180
7500
7500
7500
25000
III. RESULTS
The life-cycle cost analysis technique [1] is applied to the
updated costs and other case study values and assumptions
from Section II of this paper. The resulting costs are the costs
added by various storage systems to each kWh of electricity
that is stored and discharged. These costs are plotted in Figs.
1-4, in which each figure shows the cost added as the
discharge time is varied.
Fig. 1. Added cost (COE) vs. discharge time, 10 MW generation application
operating 250 d/yr.
3
increases as the replacement period decreases.
Table IV summarizes the results for all storage systems
operating as designed.
TABLE IV
ADDED COST (COE) USING SYSTEM AS DESIGNED
System design
Generation, 250 days/yr (batteries)
Fig. 2. Added cost (COE) vs. discharge time, 10 MW generation application
operating 100 d/yr.
Cost added (US$/kWh)
0.223-0.626
Generation, 250 days/yr (CAES)
0.196
Generation, 250 days/yr (PH)
0.151
Generation, 100 days/yr (batteries)
0.464-1.565
Generation, 100 days/yr (CAES)
0.490
Generation, 100 days/yr (PH)
0.377
T&D, 250 days/yr (batteries)
0.157-2.252
T&D, 250 days/yr (CAES)
T&D, 100 days/yr (batteries)
0.128
0.384-2.589
T&D, 100 days/yr (CAES)
0.321
IV. INTERPRETATION OF RESULTS
Fig. 3. Added cost (COE) vs. discharge time, 2.5 MW T&D application
operating 250 d/yr.
Fig. 4. Added cost (COE) vs. discharge time, 2.5 MW T&D application
operating 100 d/yr.
Figs 1 and 2 show that the lowest COE for generation
applications is at the designed 8h discharge time. At shorter
times, available capacity goes unused and this causes the
increase in COE. Similarly, the lowest COE for T&D
applications is at the designed 4h discharge time as shown in
Figs. 3 and 4.
The data for generation storage systems operating 250 d/yr
and 100 d/yr are shown in Figs. 1 and 2 respectively. It can be
seen that the costs are higher for systems operating only 100
d/yr because the system fixed costs are spread over a much
lower number of total kWh stored.
The data for T&D systems operating 250 d/yr and 100 d/yr
are shown in Figs. 3 and 4 respectively. Similar to generation
results, higher costs are for 100d/yr of operation.
For both generation and T&D storage systems, the cost
The pumped hydro non-battery storage system added the
lowest cost to electricity as shown in Table IV. However, it
needs special site requirements and causes environmental
impacts.
For generation 100d/yr system design, the cost added by
CAES is slightly higher than that for Na/S because the total
capital cost of CAES is higher. For the other system designs
shown in Table IV, the cost added by CAES is less than that
for batteries. However, it has the same disadvantages of
pumped hydro.
The highest cost added by generation battery storage
systems is four times the cost of pumped hydro. For T&D
battery storage systems, the highest cost added is seventeen
times the cost of CAES.
The costs added by VB, pumped hydro, and Zn/Br storage
systems in 2012 are significantly higher than those in the
original paper. Some cost parameters could not be obtained
and were assumed negligible in the original paper, but all were
obtained from manufacturers in the 2012 update. Also, some
of the costs in the update are higher than those in the original
paper due to more accurate information provided by
manufacturers 2012. The cost added by Na/S in 2012 is less
than that calculated in the original paper because the total
capital cost for the technology has decreased.
Table V presents the recent values for peak wholesale and
average retail electricity prices in the US.
The cost added by pumped hydro, which is US$0.151/kWh,
is four times the wholesale peak, and close to the average
residential retail price.
The lowest cost battery system studied adds a cost to
electricity close to the average residential retail price, whereas
the highest cost system adds a cost sixty eight times the
wholesale peak price.
4
TABLE V
US ELECTRICITY PRICES
Conditions
VI. REFERENCES
Electricity rate (US$/kWh)
Wholesale day ahead peak
0.03788 [5]
Average US Retail, Industrial
0.0711 [6]
Average US Retail, Commercial
0.1043 [6]
Average US Retail, Residential
0.1217 [6]
[1]
[2]
[3]
The lowest cost CAES system studied adds a cost to
electricity approximately equals to the average residential
retail price, whereas the highest cost system adds thirteen
times the wholesale peak price.
[4]
V. CONCLUSION
[6]
Electric energy storage technologies can make significant
contributions to improve the efficiency and reliability of the
current electric grid. However, the cost of these technologies
plays a critical role in determining their penetration level.
A battery storage system designed to operate 250d/yr for
generation applications, adds US$0.223-0.626 to each kWh of
electric energy stored. A T&D battery storage system designed
to operate 250d/yr, adds US$0.157-2.252/kWh stored.
Similarly, a battery storage system designed to operate only
100d/yr for generation applications, adds US$0.4641.565/kWh to the cost of electricity. A T&D battery storage
system designed to operate 100d/yr, adds US$0.3842.589/kWh.
The highest cost of using a battery storage system is much
higher than average wholesale or retail prices. However, the
lowest cost is close to the average residential retail prices.
The highest cost added by generation battery storage system
is four times the cost of pumped hydro and seventeen times the
cost of CAES for T&D applications. .
Compared to battery storage system, pumped hydro and
CAES added lower costs to electricity. However, both pumped
hydro and CAES need special site requirements and have
environmental impacts to consider. If the cost of battery
storage systems continues to decrease, then in the future, they
may approach the cost of CAES and pumped hydro.
The storage system design parameters have a significant
effect on the cost added to electricity as shown in Figs.1-4.
Thus, these parameters have to be chosen carefully when
designing a storage system in order to optimize the costs added
to electricity.
The replacement period of batteries has a significant effect
on the cost added to electricity. The balances of plant and
O&M costs have much less effect on the added cost to
electricity when compared to replacement cost.
The technique used to evaluate storage systems cost in this
paper was implemented in a spreadsheet, which is available
from the authors.
[5]
[7]
P. Poonpun and W. Jewell, “Analysis of the Cost per Kilowatt Hour to
Store Electricity”, IEEE Trans, on Energy Conversion, vol. 23, issue 2,
June 2008.
International Renewable Energy Agency (April. 2012). “Energy Storage
Technology Brief”. [Online]. Available: http://www.irena.org/Document
Downloads/Publications/Electricity%20Storage%20-%20Technology
%20Brief.pdf
Electric Power Research Institute (Feb. 2012). “Energy Storage System
Costs 2011 Update Executive Summary”. [Online]. Available:
http://www.eosenergystorage.com/documents/EPRI-Energy-StorageWebcast-to-Suppliers.pdf
S. Schoenung, “Energy Storage Systems Cost Update” Sandia Natl.
Lab., Albuquerque, NM, Sandia Rep. SAND2011-2730, 2011.
Energy Information Administration (Nov. 2012). Wholesale day ahead
prices at selected hubs and peaks. [Online]. Available:
http://www.eia.gov/electricity/wholesale/
Energy Information Administration (Aug. 2012). Average retail price of
electricity to ultimate customers by end-use sector. [Online]. Available:
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt
_5_3
Information from price quotes and performance data provided by energy
storage device manufacturers.
Haneen Aburub received the Bachelor’s degree in mechatronics engineering
from the Hashemite University, Zarqa, Jordan, in 2012. She is currently a
Graduate Research Assistant and working toward the M.S. degree in electrical
engineering at Wichita State University.
Ward T. Jewell (M’77–F’03) received B.S.E.E. degree from Oklahoma State
University, Stillwater, in 1979, the M.S.E.E. degree from Michigan State University, East Lansing, in 1980, and the Ph.D. degree from Oklahoma State
University, in 1986.
He has been with Wichita State University, Wichita, KS, since 1987,
where he is currently a Professor of Electrical Engineering. He is the Site
Director at the Power System Engineering Research Center (PSerc), Wichita
State University. His current research interests include power quality and
advanced energy technologies.