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Impact of Battery Cost on the Economics of Hybrid Photovoltaic Power Plants


Abstract and Figures

In recent years, photovoltaic (PV) technology has experienced a rapid cost reduction. This trend is expected to continue, which in many countries drives interest in utility-scale PV power plants. The main disadvantage of such plants is that they operate only when the sun is shining. The installation of PV modules together with energy storage and/or fossil fuel backup is a way to solve that issue, but consequently increases the costs. In the last few years, however, lithium-ion batteries as well have shown a promising price reduction. This paper studies the competitiveness of a hybrid power plant that combines a PV system, lithium-ion battery and gas turbine (GT) compared to conventional fossil-fuel power plants (coal and natural gas-fired) with focus on the battery cost. To fulfil the demand an auxiliary GT is used in the hybrid PV plant, but its annual generation is limited to 20% of the total output. The metric for the comparison of the different technologies is the levelized cost of energy (LCOE). The installation of the plants is showcased in Morocco, a country with excellent solar resources. Future market scenarios for 2020 and 2030 are considered. A sensitivity analysis is performed to identify the key parameters that influence LCOE.
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1876-6102 © 2016 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy
doi: 10.1016/j.egypro.2016.10.107
Energy Procedia 99 ( 2016 ) 157 173
10th International Renewable Energy Storage Conference, IRES 2016, 15-17 March 2016,
Düsseldorf, Germany
Impact of battery cost on the economics of hybrid photovoltaic
power plants
Svetlana Afanasyevaa,*, Christian Breyera, Manfred Engelhardb
aLUT School of Energy Systems, Lappeenranta University of Technology, Skinnarilankatu 34, Lappeenranta 53850, Finland
bM+W Group GmbH, Lotterbergstraȕe 30, Stuttgart 70499, Germany
In recent years, photovoltaic (PV) technology has experienced a rapid cost reduction. This trend is expected to continue, which in
many countries drives interest in utility-scale PV power plants. The main disadvantage of such plants is that they operate only
when the sun is shining. The installation of PV modules together with energy storage and/or fossil fuel backup is a way to solve
that issue, but consequently increases the costs. In the last few years, however, lithium-ion batteries as well have shown a
promising price reduction. This paper studies the competitiveness of a hybrid power plant that combines a PV system, lithium-
ion battery and gas turbine (GT) compared to conventional fossil-fuel power plants (coal and natural gas-fired) with focus on the
battery cost. To fulfil the demand an auxiliary GT is used in the hybrid PV plant, but its annual generation is limited to 20% of
the total output. The metric for the comparison of the different technologies is the levelized cost of energy (LCOE). The
installation of the plants is showcased in Morocco, a country with excellent solar resources. Future market scenarios for 2020 and
2030 are considered. A sensitivity analysis is performed to identify the key parameters that influence LCOE.
© 2016 The Authors. Published by Elsevier Ltd.
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy.
Keywords: photovoltaic; hybrid PV plant; lithium-ion battery; coal power plant; gas power plant; power supply security; dispatchable generation
1. Introduction
Solar energy is one of the primary sources of energy among renewable energy (RE) options. To convert sunlight
into electricity one of the most popular utility-scale options is the photovoltaic (PV) power plant [1]. Prices of PV
* Corresponding author. Fax: +358-5-621-2350.
E-mail address:
Available online at
© 2016 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy
158 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
systems have been dropping dramatically with an average learning rate of 20.9% [2], [3]. In the last 5 years the
global annual installation rate of PV systems averaged around 40 GW, resulting in more than 234 GW being in
operation by the end of 2015 [3], [4]. Among newly installed PV capacities about 50% are utility-scale projects.
And in many countries the interest continues to grow [3]. With higher penetration of RE, dispatchability and flexible
power generation is becoming increasingly important. The main disadvantage of PV plants is the intermittency of
power production. This can be solved by installing PV in tandem with batteries, which is more costly but better
fulfils the load requirements. Lithium-ion (Li-ion) batteries showed a great reduction in costs in recent years and
further experience curve driven cost reductions are expected [5]–[8], which makes hybrid PV-Battery plants more
competitive for utility-scale applications.
In this paper a feasibility analysis and a benchmarking based on future market scenarios are presented to identify
whether PV is economically feasible for a utility-scale application. A hybrid PV-Battery-Gas Turbine (GT) plant is
benchmarked with several utility-scale fossil-fuel power plants: (1) coal-fired, (2) open cycle gas turbine (OCGT)
and (3) combined cycle gas turbine (CCGT) plants. Wet and dry cooling systems are considered for coal-fired and
CCGT power plants.
For a comprehensive and objective comparison, the functionality of the hybrid PV plant has to match the
functionality of fossil-fuel power plants, i.e. the production profiles have to follow a given demand. For the hybrid
PV plant, a PV single-axis tracking system, Li-ion batteries and gas turbines for balancing are chosen.
Power plants connected to the grid must operate under varying environmental conditions and under changing
load, start-ups and shut-downs, etc. The efficiency of the power plants is strongly affected by the actual operation
conditions. Many studies use a single “design point” efficiency value when comparing different technologies [9],
which can easily cause misleading conclusions. In this paper the operation of the plants is modeled on an hourly
resolution taking into account variations in component performance.
The resource and demand profile are considered as fixed scenarios for the site of Ouarzazate in Morocco
(30.9167° N, 6.9167° W) and are related to the load profile of Morocco, respectively. The components of the hybrid
PV plant are dimensioned to limit the electricity generation by the natural gas-fired GT to 20%. Ultimately, the
LCOE of each plant is compared.
2. Methodology
This section focuses on the power plants’ design and discusses the aspects affecting the production efficiency.
The method for the economic analysis of the technologies is described.
2.1. Power plant components
Fig. 1-4 show the schematic of the considered power plants’ layouts, connected to the grid. The main components
are listed below.
Hybrid Photovoltaic (PV) power plant:
xPV modules
xSingle-axis tracking system
xLithium-ion batteries
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 159
Fig. 1. Schematic view of hybrid PV power plant.
Coal-fired power plant:
xsteam turbine
Fig. 2. Schematic view of coal-fired power plant.
Open cycle gas turbine power plant:
xgas turbine
Fig. 3. Schematic view of OCGT power plant.
Combined cycle gas turbine power plant:
xgas turbine
xsteam turbine
160 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
Fig. 4. Schematic view of CCGT power plant.
2.2. Modeling of hybrid PV-Battery-GT plant
The nominal capacity of the considered power plant is 100 MW AC. A standard PV system layout is assumed as
shown in Fig. 5. A modular design approach is considered. It has shown to be a successful industrial solution, since
it gives greater flexibility in designing the power plant. The plant is divided into ten independent medium voltage
sectors. Each sector has five 2000 kVA low voltage to medium voltage (LV/MV) transformers. To every
transformer two 1000 kW inverters with a corresponding array of PV modules are connected. To decrease the LCOE
of the plant, a DC overdimensioning factor of around 140% is chosen. This means a PV unit of 1408 kWp is
installed for every 1000 kW inverter unit, or 2816 kWp for every standard block. PV modules and batteries are
coupled on the AC side. It is assumed that two battery blocks of 3000 kWh with a C-rate (which is the rate at which
the battery is discharged with a specified continuous current) of 0.33 are installed to each inverter, resulting in a
discharge time of six hours. Additionally, two 50 MW GT are chosen for backup.
Fig. 5. Hybrid PV-Battery-GT power plant schematic layout.
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A substation is installed for the connection to the grid. It includes a transformer to change the voltage level from
medium to high (MV/HV transformer), switchgear, protection, measuring and control equipment.
2.2.1. PV system modeling
A single axis tracking system is considered, which can typically increase annual energy yield up to 25-35% [3],
[10]. PV modules are installed in a single-row with portrait orientation and row spacing of 2.5 m for easy access.
Backtracking is assumed for single-axis tracking, to reduce shading losses.
The production of the PV single axis tracking system is calculated using the software PVsyst [11], which is
widely used in the industry. The components considered for simulation are PV modules JAP6-72/300-320/3BB [12],
with a rated efficiency of 16.51%, and inverters Sunny Central 1000CP XT by SMA [13]. Overall 44,000 modules
are installed with a combined area of 85,289 m2, resulting in 2122 full load hours (FLh) for the considered PV
2.2.2. Battery storage system modeling
In this paper a simple battery model is used. It accounts for self-discharge, degradation and charge/discharge
losses. Temperature effects are not considered and it is assumed that the batteries are installed in an environment
with recommended operating temperature. Cooling demand is taken into account as additional 1% power loss. The
maximum capacity fade is parameterized as guaranteed by some producers by the end of the operational lifetime of
the battery. The degradation per full cycle is modelled as a ratio of the maximum capacity fade to the total number
of cycles.
2.2.3. OCGT modeling
The net efficiency
net and power output Pnet are calculated as
ambamb PTloadISOgrossnet fff
where Kgross ISO is the efficiency of the gas turbine at the standard ISO conditions, fload, fTamb and fPamb are the
correction factors due to variation in the load, ambient temperature and pressure, respectively.
parasiticnetISOgrossnet 1PrPP
where Pgross ISO is the GT power output at ISO conditions,
net is the efficiency for changed operation conditions,
r(Pparasitic ) is the ratio of parasitic consumption because of the losses, e.g. due to bearing friction, which is assumed
0.1% of the nominal capacity.
In this paper, approximate equations are used for correction factors that were obtained from analysis of data from
different measurement campaigns. Variations in efficiency due to load and temperature are shown in Fig. 6. A
change of the ambient pressure affects power output of the GT proportionally.
162 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
Fig. 6. Efficiency of the OCGT with varying ambient temperature and load.
2.2.4. Operation rules for hybrid PV plant
Operation rules for the hybrid PV power plant are set to yield the annual energy. To simulate the propagation of
the state of charge (SoC) of the battery, the Euler method with an integration step size of one hour is used.
iEtftEE SoCSoC1SoC ,'
where ESoC i and ESoC i +1 is the SoC at time ti and ti+1, respectively,
t is the time step from time ti to ti+1, and
f(ti,ESoC i) is the ordinary differential equation, which is integrated numerically
tPPEtf iiii ' dischargedischargechargechargeSoC
where Pcharge i and
charge are the power and efficiency when the battery is charged, Pdischarge i and
discharge are the
power and efficiency when the battery is discharged.
For every hour the power plant production must follow the demand. An example of a typical operation day is
shown in Fig. 7.
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 163
Fig. 7. Example of a daily operation cycle: Eload is the demand energy, EPV is the energy supplied to the net from PV modules directly, EGT is the
production from auxiliary GT, Ebattery discharge is the energy supplied from batteries, Ebattery charge is the energy during charging mode of the battery,
Eproduced by PV is the overall available energy and Edumped PV is the dumped energy that is produced by solar panels, Efrom grid is the energy required by
the plant from the grid during shut-downs.
xt1-t2: standby operation, energy is consumed by the grid due to parasitic electrical consumption of inverter,
isolation transformer, control, protection systems, etc.
00,0 gridfromPVload !o EEE (5)
xt2-t3: load covered partly by battery and partly by GT
GTdischargebatteryloadPVload 0,0,0 EEESoCEE o! ! (6)
xt3-t4: load covered by GT
GTloadPVload 0,0,0 EESoCEE o ! (7)
xt4-t5: load covered partly by PV and partly by GT
GTPVloadPVload 0,0,0 EEESoCEE o !! (8)
xt5-t6: battery is in charge mode, as battery charge is limited, a part of the energy is dumped
PVdumpedchargebatteryPVbyproducedloadloadPVload ,0 EEEEEEE o!! (9)
164 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
xt6-t7: battery is in discharge mode, part of load covered by PV, part by battery and rest by GT
GTdischargebatteryPVloadPVloadload 0,,0 EEEESoCEEE o!!! (10)
xt7-t8: equivalent to t2-t3
xt8-t1: equivalent to t1-t2
2.3. Modeling of fossil- fired power plant
Three types of conventional fossil-fired power plants are studied: coal-fired, OCGT and CCGT. Additionally, wet
and dry-cooling systems are considered for coal-fired and CCGT plants.
The same conditions as for the hybrid PV plant are set: the fossil-fired power plant’s output must follow the load.
At part-load operation, the power plant output efficiency decreases. For OCGT the efficiency curve shown in Fig. 6
is used. For coal-fired and CCGT plant efficiency, the curve is based on [14] and is shown in Fig. 8 and Fig. 9,
respectively. Power output and efficiency are calculated with Eq. (1) and Eq. (2).
Fig. 8. Efficiency of the CCGT plant with varying ambient temperature and load.
Fig. 9. Efficiency of the coal-fired power plant with varying ambient temperature and load.
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 165
The start-up energy required for the OCGT is negligible. For the CCGT it is assumed that start-up takes 40 min
and it requires half of the thermal energy needed for a full load hour. Parasitic losses for the steam turbine are 2.5%
of maximum power. For coal-fired and CCGT power plants with dry cooling systems the efficiency drops 3%
absolutely [15] and investments are 10% higher [16], [17].
2.4. Economic analysis method
Levelized cost of electricity (LCOE) is one of the most popular metrics to compare power plants with a different
type of energy resource, operating lifetime or/and cost structure [18]. Fundamentally LCOE is the ratio of the
accumulated costs, discounted to the present, and the electricity produced over the project lifetime, i.e. it is a cost of
generating electricity. In this work the capital investment (Capex), operation and maintenance (Opex), fuel and CO2
greenhouse gas (GHG) emission costs are considered. The general formula for LCOE calculation is
where AEPel is the power plant annual electrical energy production
el (12)
The degradation of power plant components is included in the so-called performance ratio (PR). For the PV
system the PR assumed for the FLh includes an annual degradation of 0.3% [19]–[21] for crystalline silicon PV
modules over the entire lifetime averaged for the lifetime. Degradation of the batteries is considered as a function of
NFC and degradation rate per cycle. For turbines to quantify performance loss is challenging, as it is a result of wear
of different turbine components. This depends on climate, type of fuel, operation mode, number of start-ups and
shutdowns, etc. Typically, during the first 24,000 hours of operation degradation is 2-6% [22]. When degraded parts
are replaced it decreases to 1-1.5% [22]. Thus, an optimally developed maintenance strategy is essential to keep
degradation to a minimum. It is assumed that at the end of the project lifetime expected performance degradation is
approximately 5% [23].
crf is a uniform capital recovery factor, which is equal to
crf (13)
Weighted Average Cost of Capital (WACC) is the rate at which the company is expected to earn in order to
return to different investors and is commonly used as the discount rate. Usually a company is financed using equity
and debt, therefore, in this paper the basic formula for WACC calculation is used:
DE k
where E is equity and D is debt, kE and kD are rates of return on equity and interest, respectively, N is the project
Fuel cost is found from:
fuelfuel chAEPcostfuel (15)
166 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
where hfuel is the heat value and cfuel is the price of fuel.
Eventually, the annual emission cost is the product of the specific emission cost cCO2 (€ per ton of CO2) and the
specific mass 2
qand thermal annual production AEPth from burning fuel.
222 COCOfuelth,CO cqAEPcostemission (16)
CO2 emission calculation
To calculate the CO2 emission costs, firstly, the resulting mass of CO2 after burning the fuel is calculated. The
combustion of natural gas (CH4) is an exothermic reaction, as shown in the chemical equation:
OHCOOCH o2224 22 (17)
The lower heating value (LHV) of natural gas is 47.1 MJ/kg [24], i.e. burning one kilogram of fuel gives 47.1 MJ
or 0.0131 MWh of heat energy. Thus, to produce 1 MWh of heat 76.43 kg of methane is used and 210 kg of CO2 are
thth MWhkgMWhkgMMqq 210164443.76
4242 CHCOCHCO (18)
where 2
q and 4
q are specific masses, 2
Mand 4
Mare molar masses in g/mol, of CO2 and CH4,
molgmolgMMM 1614124 HCCH4 (19)
molgmolgMMM 44162122 OCCO2 (20)
Steam (thermal) coal is often used for power generation. Its grade is between bituminous coal and anthracite.
Coal varies widely in chemical composition and energy content. In this paper, coal LHV is assumed with 25.83
MJ/kg [25]. Using information about the main components proportions, the specific CO2 emissions can be
 
heatOHlCOpOklpOHC klp o222 224 (21)
OHCcoal klpMkMlMpM (22)
molgpMMpM 442 OCCO2 (23)
16112 44
coalcoalCOcoalCO 22
klp p
mMMqq (24)
where p, l and k are the proportions of carbon, hydrogen and oxygen, respectively.
In this paper, it is assumed that combustion of 1 ton of coal results in 2.36 tons of CO2 emissions [25], i.e. nearly
340 kg of CO2 are emitted to produce 1 MWhth.
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 167
3. Studied case
The installation of the plant is considered in Ouarzazate, Morocco (30.9167° N, 6.9167° W), with an annual
global horizontal irradiation of 2117 kWh/(m2·a) equal to 2703 kWh/(m2·a) incident on module pane for a single-
axis tracking PV system, based on PVsyst results. A map of the solar resource in Morocco [26] is shown in Fig. 10.
Fig. 10. Map of global horizontal irradiation (GHI) in Morocco.
The nominal capacity of the plant is 100 MW AC. The total energy of an isolated system is constant. The
derivative of energy inside the system equals the sum of powers passing the system bounds, where power going into
the system is positive and out of the system is negative. Therefore, the conservation of energy is expressed in
powers for the plants. The annual full load hours are more than 5000, according to the assumed load profile (Fig.
Fig. 11. Daily load profile.
168 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
Economic assumptions for the years 2020 and 2030 for the hybrid PV plant and the fossil-fuel plants are given in
Table 1 and Table 2, respectively. Assumptions for the PV system are derived from [27], [28], taking into account a
tracking system cost. For OCGT and CCGT plants values for Capex, Opex, lifetime and efficiency are based on
[29]. Coal-fired power plant parameters are based on [30]. For power plants with dry-cooling systems Capex is 10%
higher [16], [17]. Based on current cost numbers and cost development estimates according to [5]–[8] the numbers
for batteries are derived. The weighted average cost of capital (WACC) is 7%. Prices of gas and coal are given in
Table 2 and the price per ton of CO2 emissions is 27.4/59.8 €/tCO2 for the cost years 2020 and 2030, respectively.
The CO2 emission and fuel prices are based on [31] assumptions. Cost for the heavy metal emissions of coal-fired
power plants [32]–[35] are not taken into account and remain as further risk and cost factors for coal plants.
Table 1. Economic parameters for the hybrid PV-Battery-GT plant.
System component Dimension Capex 2020/2030 Opex fix 2020/2030 Lifetime 2020/2030
PV single-axis tracking 282 MWel 900/650 €/kWp 13.5/9.75 €/(kWp·a) 30/35
Battery Power price per MW (power
electronics, transformer,
switchgear, control)
448 MWhel,
6.2 hr,
max cycles
150/100 €/kWel 8.1/4.2 €/(kWel·a) 15/20
Energy price per MWh (BMS,
Battery, Control) 300/150 €/kWhel
Open cycle gas turbine 2x50 MWel 475 €/kWel 14.25 €/(kWel·a) 30
Table 2: Economic parameters for coal and natural gas-fired power plants.
Power plant Capex Opex fix Fuel cost 2020/2030 Lifetime Efficiency
Coal-fired steam turbine 1500 €/kWel 20 €/(kWel·a) 52.5/64.5 €/ton 40 43%
Gas-fired OCGT 475 €/kWel 14.25 €/(kWel·a) 21.8/32.1 €/MWhth 30 43%
Gas-fired CCGT 775 €/kWel 19.4 €/(kWel·a) 30 58%
4. Results and discussion
Dimensions of the hybrid PV power plant components are chosen for a minimum LCOE with a constraint of gas
share of up to 20% in the annual production. As a result the total energy produced by the hybrid PV plant to cover
the load is 562.8 GWh, from which 61% is delivered by PV modules directly, 21% from batteries and the rest by
auxiliary GT. The annual number of full cycles (NFC) of the battery is 275. An example of the power plant
operation cycle and summary on monthly and annual energy production are presented in Fig. 12.
The power plant’s AEP, consumption of fossil-fuel, CO2 emissions and LCOE values are summarized in Table 3.
Table 3: Overview of the key power plants’ operational parameters.
Power plant AEP, [GWh] Annual fossil-fuel
consumption ·103, [ton/a] Annual CO2 emissions
·103, [ton/a] LCOE 2020/2030,
Hybrid PV-Battery-GT 562.8 19.6 53.9 97.7/74.3
Coal-fired steam turbine, wet cooling 518.4 201.0 474.2 72.8/108.0
Coal-fired steam turbine, dry cooling 518.4 207.2 488.9 76.4/112.8
Gas-fired OCGT 523.7 96.6 265.8 78.5/120.9
Gas-fired CCGT, wet cooling 518.4 71.6 197.0 67.3/99.0
Gas-fired CCGT, dry-cooling 518.4 73.9 203.1 70.1/102.8
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 169
Fig. 12. Monthly and annual production values of the hybrid PV plant. Example of operational cycle for the days 90-92 of the sample year is
In Fig. 13 power plants’ LCOE for given market scenarios are shown, where each influencing component is
defined. Capex for PV system drops by almost 30% and battery cost is reduced by 50% in the assumed scenarios.
Prices of fuel and CO2 emissions are increased for 2030 (Table 2). Results indicate an advantage for the hybrid PV-
Battery-GT plant in Morocco in 2030. The OCGT plant is the least favorable compared to the other options.
Fig. 13. Power plants’ LCOE for 2020 and 2030 market scenarios.
170 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
The future battery cost development is the major unknown factor. Sensitivity analyses are performed for the
hybrid PV plant, coal fired power plant and CCGT plant for 2020, shown in Fig. 14, and for 2030, shown in Fig. 15.
It identifies the relative importance of the parameters. The parameters are changed by +50% (orange color) and –
50% (blue color) and the impact is referenced to the LCOE of the plants in Table 3.
Key parameters for the hybrid PV plant in 2020 are WACC and Capex in PV modules and batteries. These
results show that improving bankability of PV projects and reducing the overall risk for respective investments are
key priorities, which was also emphasized in [27]. The effect of the CO2 emission prices on the LCOE plays only a
minor role. However, LCOE of the coal-fired plant is most sensitive to CO2 emission price in 2030. It clearly shows
the effect that governmental policies on mitigation of GHG emissions have on the competitiveness of the two
There seems to be a very recent trend in accordance to the COP21 agreement [36] that countries decide by
regulation that newly built coal-fired power plants are not allowed anymore at all, as recently announced by
Vietnam [37] and the UK [38]. An alternative may be carbon capture and storage (CCS) technology, however, the
costs are estimated to result in about 110 – 130 €/MWh [39] for coal-based electricity and the technology may be
not available before the year 2030 [40]. Therefore, the uncertainty is not only about the appropriate CO2 price, but
also whether coal-fired power is allowed anymore at all, and whether there may be a coal-based technology
available to the market for a reasonable price.
For the CCGT power plant the greatest risk lies with the price of natural gas. CO2 emission costs have less impact
compared to coal-fired plants, as CCGTs emit less CO2. For a coal-fired plant the fuel price contributes to a lesser
part of the total LCOE, as coal is a comparably cheap resource.
Fig. 14. Tornado diagrams for sensitivity analysis of LCOE to + and – 50 % economic parameters for hybrid PV-Battery-GT plant and fossil-fuel
power plants in 2020.
Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173 171
Fig. 15. Tornado diagrams for sensitivity analysis of LCOE to + and – 50 % economic parameters for hybrid PV-Battery-GT plant and fossil-fuel
power plants in 2030.
5. Conclusion
PV technology is one of the solutions for reducing GHG emissions. The aim of this paper is to check if it is
economically viable for a utility-scale application. A comparison of utility-scale power production technologies
between the hybrid PV-Battery-GT and conventional fossil-fired power plants is presented based on the LCOE.
Market scenarios for 2020 and 2030 are considered.
The results clearly indicate that coal and natural gas fired power plants are not competitive anymore to hybrid
PV-Battery-GT plants in very sunny regions such as Morocco from 2030 onwards for the assumed scenarios when
CO2 costs are considered.
Sensitivity analysis shows the importance of WACC to the competitiveness of the hybrid PV project. The top
priority for industry is to increase confidence of the investors in the PV projects as a promising investment, but also
for governments to reduce respective investment risks. The progress in cost and performance for big stationary
battery installations are also key enablers for such hybrid power plants, as well as CO2 emission cost. The
responsibility for this incentive lies on the policy-makers of the countries.
The authors gratefully acknowledge the public financing of Bundesministerium für Umwelt, Naturschutz und
Reaktorsicherheit, Berlin, for the ‘THERMVOLT’ project under the number 41V6706. The authors would like to
thank Deutsches Zentrum für Luft- und Raumfahrt e.V. (DLR), Institut für Solarforschung and Institut für
Technische Thermodynamik, Stuttgart, for solar resource data, Fichtner GmbH for providing efficiency curves of
gas turbines and combined cycles, M+W Central Europe GmbH for description of standard PV system configuration
including battery integration. The authors would like to thank Michael Child for proofreading.
172 Svetlana Afanasyeva et al. / Energy Procedia 99 ( 2016 ) 157 – 173
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... By 2050, the largest contributors to the cost will be the PV single-axis tracking and battery plants. The contribution of wind decreases after 2030, due to no more wind plant installations and a highly competitive combination of hybrid PV-battery plants, as already found by Afanasyeva et al. for the case of Morocco [65]. However, there is still a substantial contribution from wind to the LCOE in 2050 due to the large installed capacities of wind power plants in 2030. ...
... The CO 2 emission calculations are explained in [65]. Morocco [65]. However, there is still a substantial contribution from wind to the LCOE in 2050 due to the large installed capacities of wind power plants in 2030. ...
... In 2015, this value is at about 800 g of CO2 per kWh and drops to 0 by 2040. The CO2 emission calculations are explained in [65]. Morocco [65]. ...
Full-text available
This work presents a pathway for Saudi Arabia to transition from the 2015 power structure to a 100% renewable energy-based system by 2050 and investigates the benefits of integrating the power sector with the growing desalination sector. Saudi Arabia can achieve 100% renewable energy power system by 2040 while meeting increasing water demand through seawater reverse osmosis (SWRO) and multiple effect distillation (MED) desalination plants. The dominating renewable energy sources are PV single-axis tracking and wind power plants with 243 GW and 83 GW, respectively. The levelised cost of electricity (LCOE) of the 2040 system is 49 €/MWh and decreases to 41 €/MWh by 2050. Corresponding levelised cost of water (LCOW) is found to be 0.8 €/m3 and 0.6 €/m3. PV single-axis tracking dominates the power sector. By 2050 solar PV accounts for 79% of total electricity generation. Battery storage accounts for 41% of total electricity demand. In the integrated scenario, due to flexibility provided by SWRO plants, there is a reduced demand for battery storage and power-to-gas (PtG) plants as well as a reduction in curtailment. Thus, the annual levelised costs of the integrated scenario is found to be 1–3% less than the non-integrated scenario.
... Denholm et al. compare a system with no energy storage to one with energy storage, and demonstrated that energy storage reduced total fuel costs and total start costs (for starting a generator) [43]*. Greenhouse gas emissions are often considered in energy storage decision-making internationally [2,32,48,49]*. In California, Huynh figured greenhouse gas emissions to install a 50 kW, 4 hr battery system to be 152 tons of carbon dioxide per GWh of energy [5]. ...
... Afanasyeva et al. used an LCOE calculation to compare hybrid solar and gas power plants to one another [48]*. They examined a plant that used a photovoltaic array with a battery energy storage system to provide primary power but also included a gas turbine to keep up with peak demand. ...
Full-text available
When the transmission capacity of an electrical system is insufficient to adequately serve customer demand, the transmission system is said to be experiencing congestion. More transmission lines can be built to increase capacity. However, transmission congestion typically only occurs during periods of peak demand, which occur just a few times per year; capitol-intensive investments in new transmission capacity address problems that occur infrequently. Alternative solutions to alleviated transmission congestion have been devised, including generation curtailment, demand response programs, and various remedial action schema. Though not currently a common solution, battery energy storage systems can also provide transmission congestion relief. Technological and market trends indicate the growing production capacity of battery energy storage systems and decreasing prices, which indicate the technology may soon become a viable option for providing congestion relief. Batteries can provide multiple ancillary services, and so can concurrently provide value through multiple revenue streams. In this manuscript, the authors present a systematic review of literature, technology, regulations, and projects related to the use of battery energy storage systems to provide transmission congestion relief.
... Therefore, the combination of PV and battery storage is offered by the energy model as a least cost RE technology and dominates the energy system after 2040. The highly beneficial effect of hybridizing solar PV and battery storage is found in several other publications for places all around the world [24][25][26][27][28]. 7. Ratio of storage output to electricity demand for all storage options (a) and share of different resources used for power generation in total electricity production (b), both for the power scenario Fig. 8 represents the additional storage capacity which is installed in each 5-year time step. ...
... Narges Ghorbani et al. / Energy Procedia 135 (2017)[23][24][25][26][27][28][29][30][31][32][33][34][35][36] ...
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This work presents a pathway for the transition to a 100% renewable energy (RE) system by 2050 for Iran. An hourly resolved model is simulated to investigate the total power capacity required from 2015 to 2050 in 5-year time steps to fulfil the electricity demand for Iran. In addition, shares of various RE resources and storage technologies have been estimated for the applied years, and all periods before in 5-year time steps. The model takes the 2015 installed power plant capacities, corresponding lifetimes and total electrical energy demand to compute and optimize the mix of RE plants needed to be installed to achieve a 100% RE power system by 2050. The optimization is carried out on the basis of assumed costs and technological status of all energy technologies involved. Moreover, the role of storage technologies in the energy system, and integration of the power sector with desalination and non-energetic industrial gas sectors are examined. Our results reveal that RE technologies can fulfil all electricity demand by the year 2050 at a price level of about 41 - 47 €/MWhel depending on the sectorial integration. Moreover, the combination of solar PV and battery storage is found as a least cost solution after 2030 for Iran. If the capacity in 2050 would have been invested for the cost assumptions of 2050 the cost would be 32 - 40 €/MWhel, depending on the sectorial integration, which can be expected for the time beyond 2050.
... The system can supply electricity to an entire remote community at a low cost, whilst, simultaneously, reducing CO 2 emissions and rendering grid expansion unnecessary [19]. Afanasyeva et al. [20] calculated the economic competitiveness of a Moroccan hybrid power plant consisting of a photovoltaic installation, a gas turbine and batteries. They found that there was a tenfold reduction in CO 2 emissions in the hybrid power plant compared to a conventional power plant. ...
Full-text available
Increasing amounts of fluctuating renewable energy lead to decreasing electricity prices and impair security of electricity supply. Consequently, sustainable and economically feasible solutions need to be found to ensure both ongoing renewable energy expansion and stable electricity supply. We examine the impact of batteries on security of the electricity supply and achieving renewable energy expansion. For this purpose we develop an electricity market model that enables the simulation of batteries both as an economic-driven investment option and as a government subsidized option. We present six policy scenarios in which batteries are utilized as an option that is subsidized by the government to secure electricity supply and engender renewable energy expansion. Our simulations, based on empirical data, indicate that, in a free market, battery investments are not profitable for private investors. On the other hand, these six policy scenarios show that by subsidizing investments in batteries governments could ensure a secure electricity supply as well as ongoing renewable energy expansion. A comparison to similar policy scenarios that do not adopt batteries indicates that the total sum of government subsidies and external costs is up to 36% lower when utilizing batteries.
... Appendix C. Utility-scale single-axis tracking PV system design parameters See Table C1. A modular design of the PV plant is considered (Afanasyeva et al., 2016). Typically, the utility-scale PV system consists of independent medium voltage sectors. ...
The two main options on the market for utility-scale photovoltaic (PV) installations are fixed-tilted and single-axis tracking systems with a horizontal north-south-orientated axis. However, only a few global energy system studies consider the latter. The objective of this paper is to investigate the impact of single-axis tracking PV on energy scenarios. For this purpose, two scenarios with and without the single-axis tracking option are studied for 100% renewable energy (RE) systems in 2030. To find the optimum energy mix for both scenarios, the total annual cost computed by the LUT Energy System model is minimized. The satellite-based input global data have a temporal resolution of one hour and a spatial resolution of 0.45° × 0.45°. Furthermore, a model to estimate the annual yield of single-axis tracking PV is proposed and validated by using the PVsyst software. The simulation results are found to be within a 4% margin to the respective simulation results of PVsyst. Both scenarios demonstrate that a 100% RE system is possible at a low cost, where PV and wind power are the dominating generation technologies. Nevertheless, the results also show a significant effect of single-axis tracking PV. The global generation share of PV increases from 47% to 59%, and 20% of the total electricity is generated by single-axis tracking PV, while the share of wind energy decreases from 31% to 21%. Additionally, curtailment, power transmission requirements, storage demand, and the total cost decrease. The global average levelized cost of electricity decreases by 6% from 54.8 to 51.4 €/MWh. The findings indicate that energy system modeling should include single-axis tracking.
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There are undeniable signs from all over the world demonstrating that climate change is already upon us. Numerous scientific studies have warned of dire consequences should humankind fail to keep average global temperatures from rising beyond 1.5°C. Drastic measures to eliminate greenhouse gas emissions from all economic activities across the world are essential. Major emphasis has been on the energy sector, which contributes the bulk of GHG emissions. Inevitably, energy scenarios describing future transition pathways towards low, and zero emissions energy systems are commonly proposed as mitigation strategies. However, there is growing awareness in the research community that energy transitions should be understood and analysed not only from technical and economical perspectives but also from a social perspective. This research explores the broader ramifications of a global energy transition from various dimensions: costs and externalities of energy production, democratisation of future energy systems and the role of prosumers, employment creation during energy transitions at the global, regional and national levels and the effects of air pollution during energy transitions across the world. This research builds on fundamental techno-economic principles of energy systems and relies firmly on a cost driven rationale for determining cost optimal energy system transition pathways. Techno-economic analyses of energy transitions around the world are executed with the LUT Energy System Transition Model, while the corresponding socioeconomic aspects are expressed in terms of levelised cost of electricity, cost effective development of prosumers, job creation, and the reduction of greenhouse gas emissions along with air pollution. Findings during the course of this original research involved novel assessments of the levelised cost of electricity encompassing externalities across G20 countries, cost optimal prosumer modelling across the world, estimates of job creation potential of various renewables, storage and power-to-X technologies including the production of green hydrogen and e-fuels during global, regional and national energy transitions. The novel research methods and insights are published in several articles and presented in this thesis, which highlight robust socioeconomic benefits of transitioning the current fossil fuels dominated global energy system towards renewables complemented by storage and flexible power-to-X solutions, resulting in near zero emissions of greenhouse gases and air pollutants. These research findings and insights have significant relevance to stakeholders across the energy landscape and present a compelling case for the rapid transformation of energy systems across the world. However, the research does have limitations and is based on energy transition pathways that are inherent with uncertainties and some socioeconomic challenges. Nonetheless, actions to enhance and accelerate the ongoing energy transition across the world must be prioritised, if not for technical feasibility or economic viability, but for the social wellbeing of human society and future generations.
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Pathways towards a defossilated sustainable power system for West Africa within the time horizon of 2015–2050 is researched, by applying linear optimisation modelling to determine the cost optimal generation mix to meet the demand based on assumed costs and technologies in 5-year intervals. Six scenarios were developed, which aimed at examining the impact of various policy constraints such as cross-border electricity trade and greenhouse gas emissions costs. Solar PV emerges as the prime source of West Africa's future power system, supplying about 81–85% of the demand in the Best Policy Scenarios for 2050. The resulting optimisation suggests that the costs of electricity could fall from 70 €/MWh in 2015 to 36 €/MWh in 2050 with interconnection, and to 41 €/MWh without interconnection in the Best Policy Scenarios by 2050. Whereas, the levelised cost of electricity without greenhouse emission costs in the Current Policy Scenario is 70 €/MWh. Results of the optimisation indicate that a fully renewables based power system is the least-cost, least-GHG emitting and most job-rich option for West Africa. This study is the first of its kind study for the West African power sector from a long-term perspective.
Technical Report
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Technical Report "Global Energy System based on 100% Renewable Energy – Power Sector", published at the Global Renewable Energy Solutions Showcase event (GRESS), a side event of the COP23, Bonn, November 8, 2017 A global transition to 100% renewable electricity is feasible at every hour throughout the year and more cost effective than the existing system, which is largely based on fossil fuels and nuclear energy. Energy transition is no longer a question of technical feasibility or economic viability, but of political will. Existing renewable energy potential and technologies, including storage can generate sufficient and secure power to cover the entire global electricity demand by 2050 . The world population is expected to grow from 7.3 to 9.7 billion. The global electricity demand for the power sector is set to increase from 24,310 TWh in 2015 to around 48,800 TWh by 2050. Total levelised cost of electricity (LCOE) on a global average for 100% renewable electricity in 2050 is 52 €/MWh (including curtailment, storage and some grid costs), compared to 70 €/MWh in 2015. Solar PV and battery storage drive most of the 100% renewable electricity supply due to a significant decline in costs during the transition. Due to rapidly falling costs, solar PV and battery storage increasingly drive most of the electricity system, with solar PV reaching some 69%, wind energy 18%, hydropower 8% and bioenergy 2% of the total electricity mix in 2050 globally. Wind energy increases to 32% by 2030. Beyond 2030 solar PV becomes more competitive. Solar PV supply share increases from 37% in 2030 to about 69% in 2050. Batteries are the key supporting technology for solar PV. Storage output covers 31% of the total demand in 2050, 95% of which is covered by batteries alone. Battery storage provides mainly short-term (diurnal) storage, and renewable energy based gas provides seasonal storage. 100% renewables bring GHG emissions in the electricity sector down to zero, drastically reduce total losses in power generation and create 36 million jobs by 2050. Global greenhouse gas emissions significantly reduce from about 11 GtCO2eq in 2015 to zero emissions by 2050 or earlier, as the total LCOE of the power system declines. The global energy transition to a 100% renewable electricity system creates 36 million jobs by 2050 in comparison to 19 million jobs in the 2015 electricity system. Operation and maintenance jobs increase from 20% of the total direct energy jobs in 2015 to 48% of the total jobs in 2050 that implies more stable employment chances and economic growth globally. The total losses in a 100% renewable electricity system are around 26% of the total electricity demand, compared to the current system in which about 58% of the primary energy input is lost.
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Energy efficiency (EE) and renewable energy (RE) can benefit public health and the climate by displacing emissions from fossil-fuelled electrical generating units (EGUs). Benefits can vary substantially by EE/RE installation type and location, due to differing electricity generation or savings by location, characteristics of the electrical grid and displaced power plants, along with population patterns. However, previous studies have not formally examined how these dimensions individually and jointly contribute to variability in benefits across locations or EE/RE types. Here, we develop and demonstrate a high-resolution model to simulate and compare the monetized public health and climate benefits of four different illustrative EE/RE installation types in six different locations within the Mid-Atlantic and Lower Great Lakes of the United States. Annual benefits using central estimates for all pathways ranged from US5.7-US210 million (US14-US170 MWh 1), emphasizing the importance of site-specific information in accurately estimating public health and climate benefits of EE/RE efforts.
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To properly evaluate the prospects for commercially competitive battery electric vehicles (BEV) one must have accurate information on current and predicted cost of battery packs. The literature reveals that costs are coming down, but with large uncertainties on past, current and future costs of the dominating Li-ion technology. This paper presents an original systematic review, analysing over 80 different estimates reported 2007-2014 to systematically trace the costs of Li-ion battery packs for BEV manufacturers. We show that industry-wide cost estimates declined by approximately 14% annually between 2007 and 2014, from above US$1,000 per kWh to around US$410 per kWh, and that the cost of battery packs used by market-leading BEV manufacturers are even lower, at US$300 per kWh, and has declined by 8% annually. Learning rate, the cost reduction following a cumulative doubling of production, is found to be between 6 and 9%, in line with earlier studies on vehicle battery technology. We reveal that the costs of Li-ion battery packs continue to decline and that the costs among market leaders are much lower than previously reported. This has significant implications for the assumptions used when modelling future energy and transport systems and permits an optimistic outlook for BEVs contributing to low-carbon transport.
In order to define a cost optimal 100% renewable energy system, an hourly resolved model has been created based on linear optimization of energy system parameters under given constrains. The model is comprised of five scenarios for 100% renewable energy power systems in North-East Asia with different high voltage direct current transmission grid development levels, including industrial gas demand and additional energy security. Renewables can supply enough energy to cover the estimated electricity and gas demands of the area in the year 2030 and deliver more than 2000 TW hth of heat on a cost competitive level of 84 €/MW hel for electricity. Further, this can be accomplished for a synthetic natural gas price at the 2013 Japanese liquefied natural gas import price level and at no additional generation costs for the available heat. The total area system cost could reach 69.4 €/MW hel, if only the electricity sector is taken into account. In this system about 20% of the energy is exchanged between the 13 regions, reflecting a rather decentralized character which is supplied 27% by stored energy. The major storage technologies are batteries for daily storage and power-to-gas for seasonal storage. Prosumers are likely to play a significant role due to favourable economics. A highly resilient energy system with very high energy security standards would increase the electricity cost by 23% to 85.6 €/MW hel. The results clearly show that a 100% renewable energy based system is feasible and lower in cost than nuclear energy and fossil carbon capture and storage alternatives.
The world today depends on oil, coal and gas (in that order of importance) for over 80% of its primary energy. From the time humans tamed fire, wood or bio-mass became the primary energy source. Coal took over from biomass during the Industrial Revolution and accounted for over 60% of world primary energy by the early 1900s. The current age is often referred to as the Oil Age, which seems appropriate now that about 35% of the world's primary energy still comes from oil. However, coal is experiencing a renaissance. Today about one quarter of the world's primary energy and more than 40% of the world's electricity comes from coal. In addition, about two thirds of the world's steel is produced using coal. The author predicts that coal will become even more important in the decades to come, mainly driven by demand from China and India. This book focuses on the role of coal for today's energy and, most importantly, electricity markets. It starts with a review of coal as a resource, profiling the major steam coal exporting nations and the structure of the supply market. The low investment rate in coal compared to other fossil fuels is discussed, and environmental and safety issues with coal production are reviewed. The book examines how coal is used in the modern world. It compares coal to other energy resources and speculates on a greater role for coal in the medium-term future. It examines the structure of the steam coal market, contract terms, derivative markets, FOB costs, and introduces the WorldCoal market model. The final chapter summarizes conclusions and predictions. The author predicts more and larger merger attempts in the coal supply arena and further efforts to manage this development through public policy, greater investment by market participants in logistics and upstream assets, and the development of exchange-based coal trading through standardized coal volumes. The author also outlines why he believes coal prices will rise, eventually catching up with gas.
Conference Paper
Photovoltaics (PV) is expected to become one of the cheapest forms of electricity generation during the next decades. The Levelised Cost of Electricity (LCOE) of PV has already reached grid parity with retail electricity in many markets and is approaching wholesale parity in some countries. In this paper, it is estimated that the PV LCOE in main European markets is going to decrease from 2015 to 2030 by about 45% and to 2050 by about 60%. The LCOE for utility-scale PV in Europe will be about 25-45 €/MWh in 2030 and about 15-30 €/MWh in 2050 depending on the location. The weighted average cost of capital (WACC) is the most important parameter together with the annual irradiation in the calculation of the PV LCOE. The uncertainty in capital and operational expenditure (CAPEX and OPEX) is relatively less important while the system lifetime and degradation have only a minor effect. The work for this paper has been carried out under the framework of the EU PV Technology Platform.
This paper provides a comprehensive, updated picture of energy subsidies at the global and regional levels. It focuses on the broad notion of post-tax energy subsidies, which arise when consumer prices are below supply costs plus a tax to reflect environmental damage and an additional tax applied to all consumption goods to raise government revenues. Post-tax energy subsidies are dramatically higher than previously estimated, and are projected to remain high. These subsidies primarily reflect under-pricing from a domestic (rather than global) perspective, so even unilateral price reform is in countries’ own interests. The potential fiscal, environmental and welfare impacts of energy subsidy reform are substantial.