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A Cost Optimized Fully Sustainable Power System for Southeast Asia and the Pacific Rim

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In this paper, a cost optimal 100% renewable energy based system is obtained for Southeast Asia and the Pacific Rim region for the year 2030 on an hourly resolution for the whole year. For the optimization, the region was divided into 15 sub-regions and three different scenarios were set up based on the level of high voltage direct current grid connections. The results obtained for a total system levelized cost of electricity showed a decrease from 66.7 €/MWh in a decentralized scenario to 63.5 €/MWh for a centralized grid connected scenario. An integrated scenario was simulated to show the benefit of integrating additional demand of industrial gas and desalinated water which provided the system the required flexibility and increased the efficiency of the usage of storage technologies. This was reflected in the decrease of system cost by 9.5% and the total electricity generation by 5.1%. According to the results, grid integration on a larger scale decreases the total system cost and levelized cost of electricity by reducing the need for storage technologies due to seasonal variations in weather and demand profiles. The intermittency of renewable technologies can be effectively stabilized to satisfy hourly demand at a low cost level. A 100% renewable energy based system could be a reality economically and technically in Southeast Asia and the Pacific Rim with the cost assumptions used in this research and it may be more cost competitive than the nuclear and fossil carbon capture and storage (CCS) alternatives.
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energies
Article
A Cost Optimized Fully Sustainable Power System
for Southeast Asia and the Pacific Rim
Ashish Gulagi *, Dmitrii Bogdanov and Christian Breyer
School of Energy Systems, Lappeenranta University of Technology, Skinnarilankatu 34,
53850 Lappeenranta, Finland; dmitrii.bogdanov@lut.fi (D.B.); christian.breyer@lut.fi (C.B.)
*Correspondence: ashish.gulagi@lut.fi; Tel.: +358-29-4462111
Academic Editor: Lieven Vandevelde
Received: 2 March 2017; Accepted: 19 April 2017; Published: 25 April 2017
Abstract:
In this paper, a cost optimal 100% renewable energy based system is obtained for Southeast
Asia and the Pacific Rim region for the year 2030 on an hourly resolution for the whole year. For the
optimization, the region was divided into 15 sub-regions and three different scenarios were set up
based on the level of high voltage direct current grid connections. The results obtained for a total
system levelized cost of electricity showed a decrease from 66.7
/MWh in a decentralized scenario to
63.5
/MWh for a centralized grid connected scenario. An integrated scenario was simulated to show
the benefit of integrating additional demand of industrial gas and desalinated water which provided
the system the required flexibility and increased the efficiency of the usage of storage technologies.
This was reflected in the decrease of system cost by 9.5% and the total electricity generation by 5.1%.
According to the results, grid integration on a larger scale decreases the total system cost and levelized
cost of electricity by reducing the need for storage technologies due to seasonal variations in weather
and demand profiles. The intermittency of renewable technologies can be effectively stabilized to
satisfy hourly demand at a low cost level. A 100% renewable energy based system could be a reality
economically and technically in Southeast Asia and the Pacific Rim with the cost assumptions used
in this research and it may be more cost competitive than the nuclear and fossil carbon capture and
storage (CCS) alternatives.
Keywords:
100% renewable energy; Southeast Asia; Australia; energy system optimization; storage;
grid integration; economics
1. Introduction
Electricity is a significant factor for rapid industrialization, urbanization and improving quality
of life [
1
]. In the 21st century, demand for electricity is rising and will continue to do so due to
industrialization in developing and emerging countries. Providing affordable, accessible, reliable, low
to zero carbon electricity in developing and emerging countries will be the main aim of electricity
generation in the next decades [
2
]. The region of Southeast Asia and the Pacific Rim (from hereafter
Southeast Asia and the Pacific Rim will be called Southeast Asia) consists of developed countries such
as Australia, New Zealand and Singapore, as well as fast developing and emerging economies such as
Brunei, Cambodia, Indonesia, Laos, Malaysia, Myanmar, Papua New Guinea, the Philippines, Thailand,
Timor-Leste and Vietnam [
3
]. The developing region was home to approximately 630 million people
in the year 2015 [
4
] and the need for energy has been higher and growing rapidly due to increasing
population and industrialization since the Asian Financial Crisis of 1997–1998 [
5
7
]. To sustain growth
and development, demand for electricity will be 3–4 times the demand of the year 2013 by 2040 [
5
].
On the other hand, Australia and New Zealand, which are well developed economies, have higher per
capita electricity use than the Southeast Asian member states. Australia has one of the highest emissions
per capita in the developed world due to its use of coal in electricity generation [
8
]. To overcome
Energies 2017,10, 583; doi:10.3390/en10050583 www.mdpi.com/journal/energies
Energies 2017,10, 583 2 of 25
the above-mentioned challenges and meet the electricity demand for economic growth at least cost
and with the lowest possible greenhouse gas emissions is a huge challenge for the Southeast Asian
region [
9
]. Therefore, development of a 100% renewable energy (RE) based energy system is of utmost
priority [
10
,
11
]. Northern and central regions of Australia are excellent in terms of solar resources
and the southern, western and eastern coasts are good for wind [
12
,
13
]. New Zealand has a high
potential for hydropower and geothermal energy [
14
,
15
]. In addition, the Association of Southeast
Asian Nations (ASEAN) region as a whole is richly endowed with hydro, solar, geothermal, wind, and
biomass resources which can be used for the generation of electricity [
16
]. The Asian Development
Bank has estimated high technical potential for solar, wind, biofuel and biogas in the Greater Mekong
Region [
17
] and provides an outline for various business models for investments in renewable energy
(RE) for achieving its full potential [18].
The Southeast Asian region is rich in RE resources and their potential can be maximized if there
is an infrastructure for interconnection of the region’s electricity grids [
13
]. There have been various
studies undertaken on 100% RE or high share of RE based electricity systems in a specific country or
combining some of the countries of Southeast Asian region. A brief summary of the studies undertaken
is presented in Table 1.
Table 1.
Various studies undertaken on 100% renewable energy (RE) for Southeast Asian region. NEM:
national electricity market; CSP: concentrating solar thermal power; PV: photovoltaic; HVDC: high
voltage direct current; OECD: Organisation for Economic Co-operation and Development; and ASEAN:
Association of Southeast Asian Nations.
Study Scope Key Findings
Elliston et al., 2012 [19] Australia (NEM region)
100% RE system technically feasible based on available RE
resources for the year 2012. CSP and PV to satisfy about half
of the total annual electricity demand
Matthew and Patrick,
2010 [20]Australia
Wind and CSP with heat storage provide the least cost
effective combination that is commercially available and can
be deployed on a large scale in Australia
Elliston et al., 2013 [21] Australia (NEM region)
Least cost options for 100% RE supply in 2030, dominated by
wind with smaller contributions from photovoltaics
Mason et al., 2010 [14] New Zealand
100% RE system based on 53–60% hydro, 22–25% wind,
12–14% geothermal, 0.2–0.3% gasification or PHS, 0.8–0.9%
wood thermal and 0.2–0.3% biogas generation is possible
replacing the current system of 32% fossil fueled
thermal generation
Blakers et al., 2012 [6] Southeast Asia and Australia
Transmission of solar electricity from Australia is cost
competitive. Demand for electricity in Southeast Asia in
2050 would be satisfied by solar electricity from Australia
and supplemented by locally produced electricity from
renewable and conventional sources
Taggart et al., 2012 [22]Asia: connecting
Australia-Southeast Asia-China
Decrease in cost of electricity from interregional connections
and decrease in regions total emission cost
Taggart, 2013 [13]Asia: connecting
Australia-Southeast Asia-China
Network of highly efficient HVDC lines connecting all
countries in 2050. Introduction of carbon pricing
Hearps and Gilbert,
2015 [23]
includes all Asian countries except
OECD Asia, China and India
Electricity mix for Southeast Asia in 2030, Solar PV (55%) in
small grids and stand-alone systems and geothermal (20%)
Teske et al., 2011 [7] ASEAN The share of renewables in the electricity generation would
be 60% by 2030 and 92% by 2050
Huber et al., 2015 [24] ASEAN
Cheapest options for electricity generation are hydro,
biomass and geothermal. Interconnections between the
countries are beneficial
The idea of an ASEAN supergrid [
25
,
26
] connecting Australia and New Zealand has already been
discussed [
27
], taking European Union-Middle East and North Africa (EU-MENA) Desertec [
28
,
29
],
Gobitec and a Northeast Asian supergrid as an initial template [
30
32
]. An example of the grid
Energies 2017,10, 583 3 of 25
connection from Australia to the ASEAN countries is shown in Figure 1[
33
]. However, integrating
all the energy sectors, incorporating a spatial and temporal resolution of energy supply and demand,
and fully considering energy infrastructure or constraints of sustainability criteria have never been
done before for this region. For the modeling of real world conditions, all this has to be taken into
account to obtain a comprehensive least cost energy system which will be based on 100% renewable
energy. Using RE resources for power generation may often lead to excess power, which needs to be
stored. This excess power can be used, for instance, in seawater reverse osmosis (SWRO) desalination
to provide clean water in many countries. Other possibilities include Power-to-heat and heat storage
technologies for industrial heating needs [
34
,
35
] and Power-to-gas [
34
37
], which can supply natural
gas for transportation, chemical, fertilizers and other industrial sectors, and can function as an enabler
of seasonal energy storage. The main aim of the paper is to design an optimal energy system based
on 100% renewable energy by proper utilization of the renewable energy resources available in
Southeast Asia.
Energies 2017, 10, 583 3 of 24
[28,29], Gobitec and a Northeast Asian supergrid as an initial template [30–32]. An example of the
grid connection from Australia to the ASEAN countries is shown in Figure 1 [33]. However,
integrating all the energy sectors, incorporating a spatial and temporal resolution of energy supply
and demand, and fully considering energy infrastructure or constraints of sustainability criteria have
never been done before for this region. For the modeling of real world conditions, all this has to be
taken into account to obtain a comprehensive least cost energy system which will be based on 100%
renewable energy. Using RE resources for power generation may often lead to excess power, which
needs to be stored. This excess power can be used, for instance, in seawater reverse osmosis (SWRO)
desalination to provide clean water in many countries. Other possibilities include Power-to-heat and
heat storage technologies for industrial heating needs [34,35] and Power-to-gas [34–37], which can
supply natural gas for transportation, chemical, fertilizers and other industrial sectors, and can
function as an enabler of seasonal energy storage. The main aim of the paper is to design an optimal
energy system based on 100% renewable energy by proper utilization of the renewable energy
resources available in Southeast Asia.
Figure 1. An example of grid connection between Australia and ASEAN. Figure taken from [33].
Figure 1. An example of grid connection between Australia and ASEAN. Figure taken from [33].
Energies 2017,10, 583 4 of 25
2. Methodology
The model optimization of the energy system is based on linear optimization of the parameters
which are applied to the system under known constraints with the assumption of a perfect foresight
of RE power generation and power demand, storage technologies, as well as water desalination and
synthetic natural gas (SNG) generation, which operate as flexible demands in the model. The model
used in this study has been described in Bogdanov and Breyer [
37
] and the next sections do not include
a detailed description of the model, its input data and the applied technologies. However, detailed
information has been provided for all the additional assumptions considered in this study. Matching
of the power generation and demand for every hour of the year 2030 is the key constraint for the
optimization. The hourly resolution of the model significantly increases the computation time; however,
it guarantees that for every hour of the year the total generation within a sub-region and electricity
import cover the local electricity demand and enable a more precise system description including
synergy effects of different system components for the power system balance. The set of applied
technologies can be easily expanded, which is one of the main features of the used Lappeenranta
University of Technology (LUT) energy system model.
2.1. Summary of the Model
Minimization of the total annual energy system cost of the power sector and the additional
flexibility demand sectors such as gas synthesis and water desalination is the main aim of the system
optimization. This cost is calculated as the sum of the annual costs of installed capacities of the
different technologies, costs of energy generation and generation ramping. In addition, included
in the system are the distributed generation and self-consumption of residential, commercial and
industrial electricity consumers (prosumers) by installing respective capacities of rooftop PV systems
and batteries. For PV prosumers, minimizing the cost of consumed energy is the main target function,
which is calculated as a sum of self-generation, annual cost and cost of electricity consumed from the
grid, minus the benefits of selling excess electricity. The prosumers can sell electricity to the grid at
2ct/kWh; however, they have to satisfy their own demand before selling.
2.2. Input Data
The model is built on many types of different constraints and datasets. Additional information
about all the input data for the model is given in Bogdanov and Breyer [
37
]. Data calculation for
geothermal energy, desalinated water demand and industrial gas demand are described here.
(1)
The geothermal potential data for every sub-region is calculated based on the already available
information on the surface heat flow rate [
38
,
39
] and the surface ambient temperature for the
year 2005 globally. Extrapolation of the available heat flow data was performed for areas where
surface heat flow data were not available. Based on these available data, different temperature
levels and available heat at the mid-point of a 1 km thick deep layer, between the depths of 1 km
to 10 km [40,41] globally with 0.45×0.45spatial resolution are derived.
(2)
Industrial gas consumption data are based on IEA statistics for energy sector demand [42].
(3)
Projected water desalination demand was determined for every sub-region. Water desalination
demand is calculated on projections for water consumption and water stress [
43
]. In the model,
it is assumed that water stress of more than 50% will be covered by seawater desalination.
The calculations for the technical constraints and financial cost of seawater reverse osmosis
desalination are described in [44].
2.3. Applied Technologies
For the Southeast Asian energy system optimization, technologies applied can be divided into
three main categories:
Energies 2017,10, 583 5 of 25
(1) Conversion of renewable energy sources into electricity
For electricity generation from renewable energy sources, technologies used are solar PV systems
which are ground mounted (optimally tilted and single-axis north-south oriented horizontal continuous
tracking) and rooftop PV, concentrating solar thermal power (CSP), onshore wind turbines, hydro
power divided into run-of-river and dams, biomass plants (biogas and solid biomass), waste-to-energy
power plants and geothermal power plants.
(2) Energy storage
The technologies used in this model for energy storage are battery storage, pumped hydro
storage (PHS), adiabatic compressed air energy storage (A-CAES), thermal energy storage (TES) and
power-to-gas (PtG) technology. The synthesis of SNG technologies are included in PtG. Technologies
such as water electrolysis, methanation, CO
2
scrubbing from air, gas storage, and both combined
and open cycle gas turbines (CCGT, OCGT) are part of the synthesis of SNG and its reconversion to
electricity. The PtG technologies have to be operated in synchronization because of the absence of
hydrogen and CO
2
storage. There is a 48-hour biogas buffer storage and part of the biogas can be
upgraded to biomethane and introduced to the gas storage.
(3) Electricity transmission
The power distribution and transmission within the sub-regions is assumed to be based on
alternating current (AC) grids and transmission grids between the regions are based on high voltage
direct current (HVDC) technology. Loss of electricity due to the length of the power lines and losses in
converter stations at the interconnection with the AC grid form the major component of the power
losses in HVDC grids. The full block model diagram is presented in Figure 2.
(4) Energy sector bridging technologies
The SNG from the PtG technology can be used for industrial gas demand rather than storage for
the electricity sector. In addition, SWRO desalination provides clean water with the use of renewable
electricity. These two technologies provide the required flexibility to the system by reducing cost of
curtailment and storage.
Energies 2017, 10, 583 5 of 24
For electricity generation from renewable energy sources, technologies used are solar PV
systems which are ground mounted (optimally tilted and single-axis north-south oriented horizontal
continuous tracking) and rooftop PV, concentrating solar thermal power (CSP), onshore wind
turbines, hydro power divided into run-of-river and dams, biomass plants (biogas and solid
biomass), waste-to-energy power plants and geothermal power plants.
(2) Energy storage
The technologies used in this model for energy storage are battery storage, pumped hydro
storage (PHS), adiabatic compressed air energy storage (A-CAES), thermal energy storage (TES) and
power-to-gas (PtG) technology. The synthesis of SNG technologies are included in PtG. Technologies
such as water electrolysis, methanation, CO
2
scrubbing from air, gas storage, and both combined and
open cycle gas turbines (CCGT, OCGT) are part of the synthesis of SNG and its reconversion to
electricity. The PtG technologies have to be operated in synchronization because of the absence of
hydrogen and CO
2
storage. There is a 48-hour biogas buffer storage and part of the biogas can be
upgraded to biomethane and introduced to the gas storage.
(3) Electricity transmission
The power distribution and transmission within the sub-regions is assumed to be based on
alternating current (AC) grids and transmission grids between the regions are based on high voltage
direct current (HVDC) technology. Loss of electricity due to the length of the power lines and losses
in converter stations at the interconnection with the AC grid form the major component of the power
losses in HVDC grids. The full block model diagram is presented in Figure 2.
(4) Energy sector bridging technologies
The SNG from the PtG technology can be used for industrial gas demand rather than storage for
the electricity sector. In addition, SWRO desalination provides clean water with the use of renewable
electricity. These two technologies provide the required flexibility to the system by reducing cost of
curtailment and storage.
Figure 2. Block diagram of the energy system model (left); and the model flowchart (right) for
Southeast Asia [45]. ST: steam turbine; PtH: power-to-heat done by heating rod; ICE: internal
coombustion engine; GT: gas turbine; PtG: power-to-gas; PHS: pumped hydro storage; HVDC: high
voltage direct current; A-CAES: adiabatic compressed air energy storage; TES: thermal energy
storage; HHB: hot heat burner; and CSP: concentrating solar thermal power.
3. Scenario Assumptions
3.1. Subdivision of the Region and Grid Structure
The region of Southeast Asia and the Pacific is subdivided into 15 sub-regions according to the
population distribution, electricity consumption and sub-region’s electricity grid structure. The sub-
regions are: New Zealand, Australia is divided into East and West, Papua New Guinea and the Papua
region of Indonesia are combined together (due to their geographical proximity, population and ease
Figure 2.
Block diagram of the energy system model (
left
); and the model flowchart (
right
) for
Southeast Asia [
45
]. ST: steam turbine; PtH: power-to-heat done by heating rod; ICE: internal
coombustion engine; GT: gas turbine; PtG: power-to-gas; PHS: pumped hydro storage; HVDC: high
voltage direct current; A-CAES: adiabatic compressed air energy storage; TES: thermal energy storage;
HHB: hot heat burner; and CSP: concentrating solar thermal power.
Energies 2017,10, 583 6 of 25
3. Scenario Assumptions
3.1. Subdivision of the Region and Grid Structure
The region of Southeast Asia and the Pacific is subdivided into 15 sub-regions according
to the population distribution, electricity consumption and sub-region’s electricity grid structure.
The sub-regions are: New Zealand, Australia is divided into East and West, Papua New Guinea and
the Papua region of Indonesia are combined together (due to their geographical proximity, population
and ease of grid connection), Indonesia Sumatra, Indonesia Java Bali (including Timor-Leste), Indonesia
Kalimantan Sulawesi (all divided according to the national electricity operator Perusahaan Listrik
Negara-PLN) [
46
], Malaysia is divided into the two sub-regions of East Malaysia (also including
Brunei due to the geographical proximity) and West Malaysia (with Singapore), the Philippines,
Myanmar, Thailand, Laos, Vietnam and Cambodia. The Pacific islands, representing less than 2% of
the population of Southeast Asia and the Pacific region, are not included in this study. However, it had
been found separately by Blechinger et al. [
47
] that a share of about 50% RE on the Pacific islands,
mainly solar PV and wind energy, represent a local least cost solution.
The grid connection of the sub-regions in Southeast Asia is shown in Figure 3, which includes the
interconnections within the countries and also between the countries, shown by dotted lines. The grid
between the sub-regions of Indonesia Sumatra and Indonesia Java is based on the development plans
to connect the two islands with HVDC cables [
48
]. The grid connections in the ASEAN region are based
on the existing connections and future planning of the interconnections between these countries [25].
Energies 2017, 10, 583 6 of 24
of grid connection), Indonesia Sumatra, Indonesia Java Bali (including Timor-Leste), Indonesia
Kalimantan Sulawesi (all divided according to the national electricity operator Perusahaan Listrik
Negara-PLN) [46], Malaysia is divided into the two sub-regions of East Malaysia (also including
Brunei due to the geographical proximity) and West Malaysia (with Singapore), the Philippines,
Myanmar, Thailand, Laos, Vietnam and Cambodia. The Pacific islands, representing less than 2% of
the population of Southeast Asia and the Pacific region, are not included in this study. However, it
had been found separately by Blechinger et al. [47] that a share of about 50% RE on the Pacific islands,
mainly solar PV and wind energy, represent a local least cost solution.
The grid connection of the sub-regions in Southeast Asia is shown in Figure 3, which includes
the interconnections within the countries and also between the countries, shown by dotted lines. The
grid between the sub-regions of Indonesia Sumatra and Indonesia Java is based on the development
plans to connect the two islands with HVDC cables [48]. The grid connections in the ASEAN region
are based on the existing connections and future planning of the interconnections between these
countries [25].
Figure 3. Southeast Asian subdivision and HVDC grid configuration.
3.2. Applied Scenarios
The different scenarios taken into consideration in this paper for the analysis of the energy
system of Southeast Asian regions are the following:
(1) Region-wide open trade scenario, in which the regions are independent of each other and have
no interconnections so the demand for electricity is covered by the respective regions’ own
generation capacity.
(2) Country-wide open trade scenario, in which there are interconnections with HVDC lines between
the regions of the same country.
Figure 3. Southeast Asian subdivision and HVDC grid configuration.
Energies 2017,10, 583 7 of 25
3.2. Applied Scenarios
The different scenarios taken into consideration in this paper for the analysis of the energy system
of Southeast Asian regions are the following:
(1)
Region-wide open trade scenario, in which the regions are independent of each other and have
no interconnections so the demand for electricity is covered by the respective regions’ own
generation capacity.
(2) Country-wide open trade scenario, in which there are interconnections with HVDC lines between
the regions of the same country.
(3)
Area-wide open trade scenario, in which the energy systems of the countries are interconnected.
(4)
Integrated scenario: Area-wide scenario plus SWRO desalination and industrial gas demand,
where PtG technology is used not only as a storage option but also covers industrial gas demand.
This increases the flexibility of the system.
3.3. Financial and Technical Assumptions
The optimization of the model is carried out on an assumed cost basis and the state of technology
for the year 2030. The capital expenditures (capex) and operational expenditures (opex) refer in general
to a kW of electrical power, in case of water electrolysis to a kW of hydrogen thermal combustion
energy, and for CO
2
scrubbing and methanation it refers to the lower heating value of hydrogen and
methane, respectively. The financial assumptions for the energy system components for the year 2030
are tabulated in Table 2. The cost assumptions for HVDC transmission lines and converter stations,
which are given as net transmission capacity (NTC), are also included. Weighted average cost of
capital (WACC) in real terms is set to 7% for all scenarios, but for residential PV prosumers, WACC is
set to 4% due to lower financial return requirements. The financial assumptions for storage systems
refer to a kWh of electricity and gas storage refers to a thermal kWh of methane at a lower heating
value. Assumptions are mainly taken from Pleßmann et al. [
49
] and also from other sources [
32
,
50
56
].
The technical assumptions concerning energy to power ratios for storage technologies, efficiency
numbers for generation and storage technologies and power losses in HVDC power lines [
28
] and
converters are presented in Supplementary Materials (Tables S1–S3).
Table 2. Financial assumptions for major energy system components.
Technology Capex [/kW] Opex Fix
[/(kW·a)]
Opex Var
[/kWh] Lifetime [a]
PV optimally tilted 550 8 0 35
PV single-axis tracking 620 9 0 35
PV rooftop 813 12 0 35
Wind onshore 1000 20 0 25
CSP (solar field) 528 11 0 25
Hydro run-of-river 2560 115.2 0.005 60
Hydro dam 1650 66 0.003 60
Geothermal energy 4860 87 0 30
Water electrolysis 380 13 0.0012 30
Methanation 234 5 0.0015 30
CO2scrubbing 356 14 0.0013 30
CCGT 775 19.4 0.001 30
OCGT 475 14.25 0.001 30
Steam turbine 600 12 0 30
Hot heat burner 100 2 0 30
Heating rod 20 0.4 0.001 30
Biomass CHP 2500 175 0.001 30
Biogas CHP 370 14.8 0.001 30
Waste incinerator 5240 235.8 0.007 20
Biogas digester 680 27.2 0 20
Biogas upgrade 250 20 0 20
Energies 2017,10, 583 8 of 25
Table 2. Cont.
Technology Capex [/kWh] Opex Fix
[/(kWh·a)]
Opex Var
[/kWh] Lifetime [a]
Battery 150 10 0.0002 10
PHS 70 11 0.0002 50
A-CAES 31 0.4 0.0012 40
TES 24 2 0 20
Gas storage 0.05 0.001 0 50
Technology Capex
[/(kWNTC·km)]
Opex Fix
[/(kWNTC·km·a)]
Opex Var
[/kWhNTC]Lifetime [a]
HVDC line on ground 0.612 0.0075 0 50
HVDC line submarine 0.992 0.0010 0 50
Technology Capex
[/kWNTC]
Opex Fix
[/(kWNTC·a)]
Opex Var
[/kWhNTC]Lifetime [a]
HVDC converter pair 180 1.8 0 50
Technology Capex [/(m3·a)] Opex Fix [/(m3a)] Opex Var [/m3]Lifetime [a]
Water desalination 2.23 0.09 0 30
Technology Capex
[/(m3·h·km)]
Opex Fix
[/(m3·h·km·a)]
Opex Var
[/m3·h·km] Lifetime [a]
Horizontal pumping and pipes 19.3 0.39 0 30
Vertical pumping and pipes 15.5 0.31 0 30
Prices of electricity for residential, commercial and industrial consumers for all the countries are
applied in order to derive benefits due to the self-consumption of solar energy. Electricity prices for
residential, commercial and industrial prosumers for Australia, Thailand, Indonesia and Malaysia are
taken from Gerlach et al. [
57
]. The electricity price in Papua New Guinea and Timor-Leste are assumed
to be similar to Indonesia. The electricity prices for Singapore and Brunei are assumed to be similar
to Malaysia. The electricity prices for New Zealand, Philippines, Myanmar, Vietnam, and Cambodia
are calculated according to assumptions from Werner et al. [
58
] that grid electricity prices rise by
5% per annum for <0.15
/kWh, by 3% per annum for 0.15–0.30
/kWh and by 1% per annum for
>0.30
/kWh. This assumption is based on the already observed increase in prices of grid electricity on
annual basis, which is also expected to continue in the future. It should be noted that electricity prices
only affect investment decision-making of PV prosumers in the model. The regional grid electricity
costs are summarized in Supplementary Materials (Table S4). The excess electricity generated by the
prosumers is assumed to be fed into the grid for a transfer selling price of 2
ct/kWh. Prosumers
cannot sell more power to the grid than their own annual consumption.
3.4. Biomass and Geothermal Potentials
The potentials for biomass and waste resources are taken from [
59
], i.e., no energy crops
are taken into account, due to strict sustainability requirements. All biowaste is divided in three
different components: solid waste, solid biomass and biogas. Solid wastes consists of municipal and
industrial used wood; solid biomass includes straw, wood and coconut residues; biogas is comprised
of excrement, municipal biowaste and bagasse. The costs for biomass are calculated using data
from [60,61]. For solid fuels a 50 /ton fee for the waste incineration is assumed.
The geothermal heat potentials for all the sub-regions were calculated based on the spatial data
for available heat, temperature and geothermal plants for depths from 1 km to 10 km. For each
0.45×0.45
area and depth, levelized cost of electricity (LCOE) for geothermal is calculated and
optimal depth is determined. The assumption for available geothermal heat is that only 25% of it will
be utilized as an upper resource limit. The total available heat for all the regions is calculated using
the same weighted average formula as for solar and wind feed-in, with an exception being the areas
with geothermal LCOE exceeding 100
/MWh, which are omitted. The calculated potentials for solid
Energies 2017,10, 583 9 of 25
biomass, biogas, solid waste and respective costs, and geothermal heat potentials are provided in
Supplementary Materials (Tables S5 and S6).
3.5. Feed-in for Solar and Wind Energy
The feed-in profiles for single-axis tracking PV, optimally tilted PV, solar CSP and wind
energy were calculated according to Bogdanov and Breyer [
37
]. The calculated full load hours for
single-axis tracking PV, optimally tilted PV, solar CSP and wind power plants are presented in Table 3.
The aggregated profiles of solar PV generation (optimally tilted and single-axis tracking), CSP solar
field and wind energy power generation normalized to maximum capacity averaged for Southeast
Asia are presented in Figure 4.
Energies 2017, 10, 583 9 of 24
(a) (b)
(c) (d)
Figure 4. Aggregated feed-in profiles for: (a) optimally tilted PV; (b) single-axis tracking PV; (c) CSP
solar field; and (d) wind power plant in Southeast Asia.
Table 3. Average full load hours and levelized cost of electricity (LCOE) for single-axis tracking PV,
optimally tilted PV, solar CSP and wind power plants in Southeast Asian regions. Pop.: population;
mio.: million; Electr.: electricity and FLH: full load hours.
Region
Pop.
[mio.
Pop]
Electr.
Demand
[TWh]
PV-
Single-
Axis
FLH
PV
Optimally
Tilted
FLH
CSP
FLH
Wind
FLH
PV
Single-
Axis
LCOE
[€/MWh]
PV
Optimally
Tilted
LCOE
[€/MWh]
CSP
LCOE
[€/MWh]
Wind
LCOE
[€/MWh]
Total area 746 1630 1905 1529 1552 1565 30 33 79 142
New Zealand 5 54 1765 1430 1541 4122 32 35 76 26
Australia East 25 245 2316 1733 2261 3500 25 29 52 30
Australia West 4 38 2397 1764 2424 3782 24 29 48 28
Indonesia Papua + Papua
New Guinea 12 16 1816 1465 1300 1182 31 34 90 90
Sumatra 58 100 1746 1445 1193 440 33 35 98 240
Java + Timor-Leste 166 148 2203 1683 2008 1225 26 30 58 86
Indonesia East 37 32 1869 1503 1467 394 30 34 80 269
Malaysia West + Singapore 34 169 1835 1485 1298 454 31 34 90 233
Malaysia East + Brunei 9 72 1810 1489 1373 170 31 34 85 623
Philippines 138 98 1929 1503 1585 1799 29 34 74 59
Myanmar 59 40 1843 1539 1591 847 31 33 74 125
Thailand 69 184 1794 1495 1360 1559 32 34 86 68
Laos 9 26 1677 1439 1248 934 34 35 94 113
Vietnam 102 385 1764 1456 1287 1838 32 35 91 58
Cambodia 19 21 1810 1512 1340 1230 31 33 87 86
Figure 4.
Aggregated feed-in profiles for: (
a
) optimally tilted PV; (
b
) single-axis tracking PV; (
c
) CSP
solar field; and (d) wind power plant in Southeast Asia.
3.6. Upper and Lower Limitations on Installed Capacities
Lower and upper limitations are set for RE sources (optimally tilted PV, wind turbines, hydro
power) and for pumped hydro storage, and were calculated according to Bogdanov and Breyer [
37
].
The data for already installed capacities (lower limits) for optimally tilted PV, wind turbines, hydro
power and pumped hydro storage for Southeast Asian sub-regions are taken from Farfan and
Breyer [
62
]. Supplementary Materials Table S7 gives the summary of the lower limits on already
installed capacities in the Southeast Asian sub-regions.
Energies 2017,10, 583 10 of 25
Table 3.
Average full load hours and levelized cost of electricity (LCOE) for single-axis tracking PV, optimally tilted PV, solar CSP and wind power plants in Southeast
Asian regions. Pop.: population; mio.: million; Electr.: electricity and FLH: full load hours.
Region Pop.
[mio. Pop]
Electr.
Demand
[TWh]
PV-Single-Axis
FLH
PV
Optimally
Tilted FLH
CSP
FLH
Wind
FLH
PV Single-Axis
LCOE [/MWh]
PV Optimally
Tilted LCOE
[/MWh]
CSP LCOE
[/MWh]
Wind LCOE
[/MWh]
Total area 746 1630 1905 1529 1552 1565 30 33 79 142
New Zealand 5 54 1765 1430 1541 4122 32 35 76 26
Australia East 25 245 2316 1733 2261 3500 25 29 52 30
Australia West 4 38 2397 1764 2424 3782 24 29 48 28
Indonesia Papua + Papua New Guinea
12 16 1816 1465 1300 1182 31 34 90 90
Sumatra 58 100 1746 1445 1193 440 33 35 98 240
Java + Timor-Leste 166 148 2203 1683 2008 1225 26 30 58 86
Indonesia East 37 32 1869 1503 1467 394 30 34 80 269
Malaysia West + Singapore 34 169 1835 1485 1298 454 31 34 90 233
Malaysia East + Brunei 9 72 1810 1489 1373 170 31 34 85 623
Philippines 138 98 1929 1503 1585 1799 29 34 74 59
Myanmar 59 40 1843 1539 1591 847 31 33 74 125
Thailand 69 184 1794 1495 1360 1559 32 34 86 68
Laos 9 26 1677 1439 1248 934 34 35 94 113
Vietnam 102 385 1764 1456 1287 1838 32 35 91 58
Cambodia 19 21 1810 1512 1340 1230 31 33 87 86
Energies 2017,10, 583 11 of 25
For hydro power plants and PHS storage, upper limits on capacities are assumed to be 150% and
200% of the already installed capacities. The upper limits for all the RE technologies for Southeast
Asian sub-region are summarized in Supplementary Materials (Table S8). The upper limits for all the
other technologies are not specified. However, for biomass residues, biogas and waste to energy plants
it is assumed, due to energy efficiency reasons, that the available and specified amount of the fuel as
summarized in Supplementary Materials (Table S5) is utilized during the year.
3.7. Load
The load profiles for all the sub-regions are calculated as a fraction of the total demand in a country
based on synthetic load data weighted by the sub-region’s population. The area aggregated demand
for all the sub-regions in Southeast Asia is given in Figure 5. A significant impact is observed on the
residual load demand due to solar PV prosumers in the energy system, which is shown in Figure 5b.
The overall electricity demand and peak load are reduced by 13.9% and 5.4%, respectively.
Energies 2017, 10, 583 10 of 24
3.6. Upper and Lower Limitations on Installed Capacities
Lower and upper limitations are set for RE sources (optimally tilted PV, wind turbines, hydro
power) and for pumped hydro storage, and were calculated according to Bogdanov and Breyer [37].
The data for already installed capacities (lower limits) for optimally tilted PV, wind turbines, hydro
power and pumped hydro storage for Southeast Asian sub-regions are taken from Farfan and Breyer
[62]. Supplementary Materials Table S7 gives the summary of the lower limits on already installed
capacities in the Southeast Asian sub-regions.
For hydro power plants and PHS storage, upper limits on capacities are assumed to be 150% and
200% of the already installed capacities. The upper limits for all the RE technologies for Southeast
Asian sub-region are summarized in Supplementary Materials (Table S8). The upper limits for all the
other technologies are not specified. However, for biomass residues, biogas and waste to energy
plants it is assumed, due to energy efficiency reasons, that the available and specified amount of the
fuel as summarized in Supplementary Materials (Table S5) is utilized during the year.
3.7. Load
The load profiles for all the sub-regions are calculated as a fraction of the total demand in a
country based on synthetic load data weighted by the sub-region’s population. The area aggregated
demand for all the sub-regions in Southeast Asia is given in Figure 5. A significant impact is observed
on the residual load demand due to solar PV prosumers in the energy system, which is shown in
Figure 5b. The overall electricity demand and peak load are reduced by 13.9% and 5.4%, respectively.
(a) (b)
Figure 5. (a) Aggregated load curve; and (b) load curve with PV prosumers influence for Southeast
Asia for the year 2030.
The demand for gas by industries (not considered is the gas demand for electricity generation,
residential and transportation sectors) and desalination water demand for Southeast Asian sub-
regions are presented in Supplementary Materials (Table S9). The gas demand values are taken from
IEA data [42]. The values for desalination are based on water stress and water consumption
projections [44].
4. Results
The optimized electrical energy system configuration is derived for each scenario, which is
characterized by optimized installed capacities for RE electricity generation, storage and transmission
for every technology used in the model. This in turn leads to hourly generation of electricity, charging
and discharging of storage technologies, import and export of electricity between regions or
countries, and curtailment. The key average financial results for the different scenarios are presented
in Table 4. The key numbers represent total system (LCOE) levelized cost of electricity (including PV
self-consumption and the centralized system), levelized cost of electricity for primary generation
Figure 5.
(
a
) Aggregated load curve; and (
b
) load curve with PV prosumers influence for Southeast
Asia for the year 2030.
The demand for gas by industries (not considered is the gas demand for electricity generation,
residential and transportation sectors) and desalination water demand for Southeast Asian sub-regions
are presented in Supplementary Materials (Table S9). The gas demand values are taken from IEA
data [
42
]. The values for desalination are based on water stress and water consumption projections [
44
].
4. Results
The optimized electrical energy system configuration is derived for each scenario, which is
characterized by optimized installed capacities for RE electricity generation, storage and transmission
for every technology used in the model. This in turn leads to hourly generation of electricity,
charging and discharging of storage technologies, import and export of electricity between regions or
countries, and curtailment. The key average financial results for the different scenarios are presented
in Table 4. The key numbers represent total system (LCOE) levelized cost of electricity (including
PV self-consumption and the centralized system), levelized cost of electricity for primary generation
(LCOE primary), levelized cost of curtailment (LCOC), levelized cost of storage technologies (LCOS),
levelized cost of transmission (LCOT), total annualized cost, total capital expenditures, total renewables
capacity and total primary generation.
Energies 2017,10, 583 12 of 25
Table 4. Key financial results for the four scenarios applied for Southeast Asian region.
2030 Scenarios
Total
LCOE
LCOE
Primary LCOC LCOS LCOT Total Ann.
Cost
Total
CAPEX
RE
Capacities
Generated
Electricity
/MWh /MWh /MWh /MWh /MWh bbGW TWh
Region-wide 66.7 44.4 1.9 20.4 0.0 109 919 763 1780
Country-wide 66.2 44.3 1.8 19.9 0.2 108 914 755 1773
Area-wide 63.5 45.6 1.1 15.8 1.0 104 883 705 1714
Integrated scenario
51.1 39.1 1.0 10.5 0.5 153 1339 1151 2794
Despite lower primary generation costs, the connection of different regions via HVDC power
lines does not yield an expected benefit, since there is no transmission of power from Australia to the
ASEAN countries. However, connection due to HVDC power lines still has a positive impact on the
LCOE and total annual costs of the system. The LCOE is decreased from the region-wide to area-wide
scenario by 4.5%, and the total annual costs of the system are decreased by 4.6%. The other benefits
of grid utilization include a decrease in installed capacities by 7.6% and in total electricity generated
by 3.7% from the region-wide to area-wide scenarios. Grid integration decreases the cost of storage
technologies and leads to utilization of transmission capacities as the cost of transmission is relatively
small in the regions where the cost of storage is not cost competitive with electricity transmission.
The power line capacities for the electricity trade between the sub-regions for the area-wide open trade
scenario is shown in Supplementary Materials (Figure S8 and Table S15).
The LCOE components and the import/export share in region-wide, country-wide, area-wide
and integrated scenario are presented in Supplementary Materials (Table S10). The share of export is
defined as the ratio of net exported electricity to the generated primary electricity of a sub-region and
the share of import is defined as the ratio of imported electricity to the electricity demand. The average
for the whole region is composed of sub-regional values weighted by the electricity demand.
A decrease in total installed capacities of RE is observed as grid utilization increases (Table 4).
For PV, the installed capacities decrease by 10% from the region-wide to area-wide scenarios, and for
wind they remain same even when the regions are interconnected. In the integrated scenario, installed
capacities of PV and wind increase due to the additional demands of seawater desalination and
industrial gas. For Southeast Asia, PV is the least cost RE source followed by wind energy. The shares
of PV single-axis tracking and PV self-consumption in the total solar PV installed capacity for the
area-wide scenario are 66.5% and 33.5%, respectively.
When comparing the region-wide and integrated scenarios, a decrease in total LCOE by 23.4% is
observed due to the integration of desalination and industrial gas demands. A decrease of 48.5% is
observed in the cost of storage technologies due to its reduced need, as additional electricity demand
flexibility is provided to the system by industrial gas synthesis and the desalination sectors. Due to
this flexible demand from two new sectors in the integrated scenario, there is an increase in installed
capacities of low cost solar PV and wind power in comparison to area-wide scenario, and a slight
decrease in biomass power plant capacities, as observed in Table 5. The share of hydro dams does
not change as it also provides required flexibility to the system. The inter-regional electricity trade
decreases between the regions due to the integration of the desalination and gas sectors, which leads
to a decrease in electricity transmission costs by 50%.
The distribution of the system optimized sub-regional RE sources can be observed from Figure 6.
Sub-regions with the best renewable resources are net exporters, and the others are net importers.
In the case of the region-wide scenario, all individual sub-regions of Southeast Asia need to satisfy
their demands using the available RE sources in that particular region. A division of regions into net
importers and exporters can be observed for the area-wide scenario and the integrated scenario, which
are presented in Figure 6. The difference observed between demand and generation is mainly due
to import and export, but also due to storage losses. For the integrated scenario, this difference is
due to energy consumption for SNG production, as shown is Figure 6. The net importer regions for
Southeast Asia and Pacific are: Malaysia West and Singapore, Thailand, Malaysia East and Brunei.
Energies 2017,10, 583 13 of 25
The net exporter regions are: Sumatra, Myanmar and Indonesia Kalimantan Sulawesi. Due to a high
electricity demand for additional desalination and SNG production, the integrated scenario tends
to show an increase in the electricity generation between the regions to fulfill the increased demand.
Hourly resolved profiles for the net importing region Malaysia West and Singapore and net exporting
region Sumatra are presented in Supplementary Materials (Figures S1 and S2, respectively).
Table 5. Results on the installed RE technologies and storage capacities for the four scenarios.
Technology Unit Region-Wide Country-Wide Area-Wide Integrated
Scenario
PV self-consumption (GW) 150 150 150 150
PV optimally tilted (GW) 5 5 5 5
PV single-axis tracking (GW) 347 341 294 604
PV total (GW) 502 495 448 758
CSP (GW) 0 0 0 0
Wind energy (GW) 115 115 115 255
Biomass power plants (GW) 31 30 31 30
MSW incinerator (GW) 3 3 3 3
Biogas power plants (GW) 25 25 21 20
Geothermal power (GW) 11 12 17 15
Hydro Run-of-River (GW) 28 28 27 27
Hydro dams (GW) 38 38 39 39
Battery PV self-consumption
(GWh) 172 172 172 172
Battery System (GWh) 591 588 507 580
Battery total (GWh) 763 759 678 752
PHS (GWh) 9 9 9 6
A-CAES (GWh) 847 780 205 269
Heat storage (GWh) 0 0 0 0
PtG electrolyzers (GWel) 11 10 4 118
CCGT (GW) 24 23 18 8
OCGT (GW) 2 2 2 0
Steam Turbine (GW) 0 0 0 0
Figure 7gives an overview of the installed capacities for RE generation and storage technologies
for all sub-regions for the region-wide, area-wide and integrated scenarios. For the region-wide
scenario in the sub-regions of New Zealand, Australia East, Australia West and Vietnam, solar PV
capacities exceed 40% of all installed RE capacities despite the full load hours (FLH) for wind being
higher or comparable to PV full load hours. It is observed that in the sub-regions that have excellent
wind conditions, low cost wind energy is the next preferred technology after solar PV, which is
lowest in cost. When comparing the region-wide and area-wide scenarios, the interconnection of the
sub-regions via HVDC transmission lines results in a decrease of the installed capacities of PV by
10.7%, as seen in Figure 7and Table 5. In the case of the integrated scenario, installed capacities for PV
and wind increase significantly, by 40.9% and 54.9%, respectively, compared to the area-wide scenario,
due to a higher demand for electricity.
The connection of the regions via HVDC transmission lines, RE generation and demand greatly
influence the total storage capacity required. In addition, they also change the combination of different
storage technologies required for the energy system in the whole region. The throughput of batteries,
A-CAES, and gas storage technologies decreases by 9.7%, 73.9% and 18.7%, respectively, from the
region-wide to the area-wide scenario. State of charge profile diagrams for the area-wide scenario
for battery, PHS, A-CAES and gas storage are given in Supplementary Materials (Figure S6). It is
observed that batteries are utilized on a daily basis with charging in the noon and afternoon hours,
with discharging in the evening and night hours to satisfy evening demand. Something similar is
observed for pumped hydro storage, but the frequency of discharge is less than batteries. Further,
gas storage discharges in the summer months, due to peak loads associated with cooling demands
resulting from hot and humid conditions in the ASEAN region. At this time of the year, we see the
utilization of gas storage and A-CAES. PV self-consumption plays a large role in Southeast Asia due
Energies 2017,10, 583 14 of 25
to higher electricity prices. PV self-generation covers 62.8%, 59.9%, 54.2% of residential, commercial
and industrial prosumers demand, respectively. An overview of PV self-consumption is provided in
Supplementary Materials (Table S11).
Energies 2017, 10, 583 13 of 24
(a)
(b)
Figure 6. Annual import and export of electricity diagrams for: (a) area-wide; and (b) integrated
scenario.
The connection of the regions via HVDC transmission lines, RE generation and demand greatly
influence the total storage capacity required. In addition, they also change the combination of
different storage technologies required for the energy system in the whole region. The throughput of
batteries, A-CAES, and gas storage technologies decreases by 9.7%, 73.9% and 18.7%, respectively,
from the region-wide to the area-wide scenario. State of charge profile diagrams for the area-wide
scenario for battery, PHS, A-CAES and gas storage are given in Supplementary Materials (Figure S6).
It is observed that batteries are utilized on a daily basis with charging in the noon and afternoon
hours, with discharging in the evening and night hours to satisfy evening demand. Something similar
is observed for pumped hydro storage, but the frequency of discharge is less than batteries. Further,
gas storage discharges in the summer months, due to peak loads associated with cooling demands
resulting from hot and humid conditions in the ASEAN region. At this time of the year, we see the
Figure 6.
Annual import and export of electricity diagrams for: (
a
) area-wide; and (
b
) integrated
scenario.
Energies 2017,10, 583 15 of 25
Energies 2017, 10, 583 14 of 24
utilization of gas storage and A-CAES. PV self-consumption plays a large role in Southeast Asia due
to higher electricity prices. PV self-generation covers 62.8%, 59.9%, 54.2% of residential, commercial
and industrial prosumers demand, respectively. An overview of PV self-consumption is provided in
Supplementary Materials (Table S11).
The impact of A-CAES on the system parameters of Southeast Asia and Eurasia was studied in
detail by Gulagi et al. [63]. A-CAES could emerge as a valuable component in a portfolio of different
storage options, as found by Fthenakis et al. [64]. There is already long-term experience with the
technology despite only two respective facilities. However, the geologic preconditions needed for A-
CAES are available all over the world [65]. Integration of A-CAES in Southeast Asia (a region with
low seasonal variation and low wind energy share) does have an effect on the system in a positive
way. However, this effect is more dramatic in Eurasia (a region with high seasonal variation and high
wind share). A summary of the important system parameters taken from [63] for Southeast Asia and
Eurasia is given in Supplementary Materials (Table S12). The utilization of low cost A-CAES
decreases overall cost of the system by decreasing the share of other storage technologies used.
Battery, gas and PHS output of electricity decreased by 5.5%, 1.6% and 0.4% in Southeast Asia. The
installation of HVDC lines had a positive impact and decreased the utilization of storage
technologies. This is due to the fact that the cost of transmitting electricity is lower in many cases than
the cost of storage options. Due to the expansion of the grid, installed capacities of batteries, PHS, A-
CAES, heat storage, PtG and gas turbines decrease. An overview of the storage capacities, throughput
of storage technologies, full cycles and utilization of available A-CAES potential for the four scenarios
for Southeast Asia and Eurasia is presented in Supplementary Materials (Table S13 and S14,
respectively) [63].
(a)
(b)
Energies 2017, 10, 583 15 of 24
(c)
Figure 7. Installed capacities RE generation (left) and storage capacities (right) for: (a) region-wide;
(b) area-wide; and (c) integrated scenarios for Southeast Asia and Pacific regions.
The electricity generation curves for the area-wide scenario are presented in Supplementary
Materials (Figure S7). A full year divided into 8760 h is represented and sorted according to the
generation minus the load, which is represented by a black line. The storage technologies are charged
for about 3800 h of the year due to higher electricity generation than demand. The reason for high
electricity generation can be attributed to the inflexibility of solar and wind energy and favorable
conditions for these technologies in these hours in Southeast Asia. As a result, other flexible options
such as hydro dams, biomass, biogas and discharge of storage technologies are required. As observed
for the other hours of the year, the inflexible electricity generation options are reduced significantly
as the electricity demand decreases and there is a need for flexible electricity generation options,
discharge of storage technologies and utilization of the grid. There is not much curtailment in the
whole year and it takes place for some hundred hours since for all the other hours the HVDC lines
enable the export of the electricity from the best RE producing sub-regions to other sub-regions with
remaining demand.
The grid utilization profile for Southeast Asia can be found in Supplementary Materials (Figure
S8). An interesting observation can be made from the grid profile that the grid is mostly utilized in
the morning hours. A possible explanation that can be provided is the seasonal variation in the
ASEAN region, where most of the trading of the electricity takes place. This region consists of two
major climatic patterns, summer from January to May, and the rainy season from May to December.
In the rainy months, due to the overcast and cloudy conditions, there is a decrease in solar radiation.
Therefore, to satisfy the morning or afternoon demands, transmission of electricity takes place
between the regions. The capacities and utilization of the transmission lines between various regions
is presented in Supplementary Materials (Table S15).The energy flow of the system, from generation
to demand in the integrated scenario, is presented in Figure 8. This flow diagram consists of RE
resources, storage technologies for the generated energy and the transmission of this energy via
HVDC grids. The end use of electricity for the integrated scenario consists of electricity, desalination
and industrial gas demands. The usable heat generated and the losses incurred are comprised of
curtailed electricity; heat produced by biomass, biogas and waste-to-energy power plants; and heat
generated from electrolyzers for transforming power-to-hydrogen, from the methanation process
transforming hydrogen-to-methane, and from methane-to-power in gas turbines. Efficiency losses
occurred in A-CAES, PHS, battery storage and HVDC transmission. The energy flow diagrams for
the region-wide and area-wide scenarios are presented in Supplementary Materials (Figure S9 and
S10, respectively).
Figure 7.
Installed capacities RE generation (
left
) and storage capacities (
right
) for: (
a
) region-wide;
(b) area-wide; and (c) integrated scenarios for Southeast Asia and Pacific regions.
The impact of A-CAES on the system parameters of Southeast Asia and Eurasia was studied in
detail by Gulagi et al. [
63
]. A-CAES could emerge as a valuable component in a portfolio of different
Energies 2017,10, 583 16 of 25
storage options, as found by Fthenakis et al. [
64
]. There is already long-term experience with the
technology despite only two respective facilities. However, the geologic preconditions needed for
A-CAES are available all over the world [
65
]. Integration of A-CAES in Southeast Asia (a region with
low seasonal variation and low wind energy share) does have an effect on the system in a positive way.
However, this effect is more dramatic in Eurasia (a region with high seasonal variation and high wind
share). A summary of the important system parameters taken from [
63
] for Southeast Asia and Eurasia
is given in Supplementary Materials (Table S12). The utilization of low cost A-CAES decreases overall
cost of the system by decreasing the share of other storage technologies used. Battery, gas and PHS
output of electricity decreased by 5.5%, 1.6% and 0.4% in Southeast Asia. The installation of HVDC
lines had a positive impact and decreased the utilization of storage technologies. This is due to the
fact that the cost of transmitting electricity is lower in many cases than the cost of storage options.
Due to the expansion of the grid, installed capacities of batteries, PHS, A-CAES, heat storage, PtG and
gas turbines decrease. An overview of the storage capacities, throughput of storage technologies, full
cycles and utilization of available A-CAES potential for the four scenarios for Southeast Asia and
Eurasia is presented in Supplementary Materials (Tables S13 and S14, respectively) [63].
The electricity generation curves for the area-wide scenario are presented in Supplementary
Materials (Figure S7). A full year divided into 8760 h is represented and sorted according to the
generation minus the load, which is represented by a black line. The storage technologies are charged
for about 3800 h of the year due to higher electricity generation than demand. The reason for high
electricity generation can be attributed to the inflexibility of solar and wind energy and favorable
conditions for these technologies in these hours in Southeast Asia. As a result, other flexible options
such as hydro dams, biomass, biogas and discharge of storage technologies are required. As observed
for the other hours of the year, the inflexible electricity generation options are reduced significantly
as the electricity demand decreases and there is a need for flexible electricity generation options,
discharge of storage technologies and utilization of the grid. There is not much curtailment in the
whole year and it takes place for some hundred hours since for all the other hours the HVDC lines
enable the export of the electricity from the best RE producing sub-regions to other sub-regions with
remaining demand.
The grid utilization profile for Southeast Asia can be found in Supplementary Materials (Figure S8).
An interesting observation can be made from the grid profile that the grid is mostly utilized in the
morning hours. A possible explanation that can be provided is the seasonal variation in the ASEAN
region, where most of the trading of the electricity takes place. This region consists of two major climatic
patterns, summer from January to May, and the rainy season from May to December. In the rainy
months, due to the overcast and cloudy conditions, there is a decrease in solar radiation. Therefore,
to satisfy the morning or afternoon demands, transmission of electricity takes place between the
regions. The capacities and utilization of the transmission lines between various regions is presented
in Supplementary Materials (Table S15). The energy flow of the system, from generation to demand in
the integrated scenario, is presented in Figure 8. This flow diagram consists of RE resources, storage
technologies for the generated energy and the transmission of this energy via HVDC grids. The end use
of electricity for the integrated scenario consists of electricity, desalination and industrial gas demands.
The usable heat generated and the losses incurred are comprised of curtailed electricity; heat produced
by biomass, biogas and waste-to-energy power plants; and heat generated from electrolyzers for
transforming power-to-hydrogen, from the methanation process transforming hydrogen-to-methane,
and from methane-to-power in gas turbines. Efficiency losses occurred in A-CAES, PHS, battery
storage and HVDC transmission. The energy flow diagrams for the region-wide and area-wide
scenarios are presented in Supplementary Materials (Figures S9 and S10, respectively).
Energies 2017,10, 583 17 of 25
Energies 2017, 10, 583 16 of 24
Figure 8. System energy flow for the integrated scenario.
5. Discussion
5.1. Discussion of Results
The installation of HVDC lines enables a decrease in the cost of electricity in the RE-based
system. However, the benefit due to grid integration is limited due to long distances and local storage
technologies being more cost competitive. For example, the low cost RE from Australia cannot be
exported to the high demand centers in Indonesia, and trading of electricity between the two
Australian regions of East and West does not take place due to long distances and respective costs.
Additionally, the available wind resource in Australia does not generate enough total benefits to
justify the cost for the HVDC power lines. This observation is in line with another similar study,
which showed that trading of RE-based SNG can reduce the total system cost without the help of
power line based electricity export from Australia [66]. The total levelized cost of electricity in
Southeast Asia and Pacific decreased from 66.7 €/MWh for the region-wide open trade scenario to
66.2 €/MWh for the country-wide open trade scenario and 63.5 €/MWh for the area-wide open trade
scenario. The total annualized cost of the system decreased from 109 b€ to 104 b€ and the capital
expenditure required for the system decreased from 919 b€ to 883 b€ for the region-wide to the area-
wide open trade scenario. For the country-wide and the area-wide scenario, the cost incurred in the
installation of HVDC transmission lines is compensated by a decrease in installed capacities of
electricity generation sources and storage capacities. This enables lower efficiency losses and import
of low cost electricity from other regions.
The integrated scenario presents a possibility to cover the projected natural gas demand in the
industrial sector (except for demand in power generation and residential use) by flexible generation
of SNG, and providing clean water in water stressed areas by SWRO desalination. The flexibility
provided by the integrated scenario to the system is most useful in compensating seasonal
fluctuations. The additional electricity demand for 572 TWhth (58.5 bcm) of SNG and 9.7 billion m3 of
clean water is covered by the RE resources available in Southeast Asia. The additional electricity
requirement of 1006 TWhel for gas synthesis and SWRO desalination is met by installing an additional
310 GW of PV and 140 GW of wind. Due to this, there is an increase in short term battery storage and
a decrease in gas storage as a consequence of the higher flexibility of the electrolyzer units. These
units are significantly increased by about 114 GW, equal to 96.6% compared to the area-wide scenario.
As well, area substantial decreases in gas turbine and biomass power plant capacities. The total
benefit for integrating the electricity, seawater desalination and industrial gas sectors is projected to
Figure 8. System energy flow for the integrated scenario.
5. Discussion
5.1. Discussion of Results
The installation of HVDC lines enables a decrease in the cost of electricity in the RE-based
system. However, the benefit due to grid integration is limited due to long distances and local storage
technologies being more cost competitive. For example, the low cost RE from Australia cannot be
exported to the high demand centers in Indonesia, and trading of electricity between the two Australian
regions of East and West does not take place due to long distances and respective costs. Additionally,
the available wind resource in Australia does not generate enough total benefits to justify the cost for the
HVDC power lines. This observation is in line with another similar study, which showed that trading of
RE-based SNG can reduce the total system cost without the help of power line based electricity export
from Australia [
66
]. The total levelized cost of electricity in Southeast Asia and Pacific decreased from
66.7 /MWh for the region-wide open trade scenario to 66.2 /MWh for the country-wide open trade
scenario and 63.5
/MWh for the area-wide open trade scenario. The total annualized cost of the system
decreased from 109 b
to 104 b
and the capital expenditure required for the system decreased from
919 b
to 883 b
for the region-wide to the area-wide open trade scenario. For the country-wide and the
area-wide scenario, the cost incurred in the installation of HVDC transmission lines is compensated by
a decrease in installed capacities of electricity generation sources and storage capacities. This enables
lower efficiency losses and import of low cost electricity from other regions.
The integrated scenario presents a possibility to cover the projected natural gas demand in the
industrial sector (except for demand in power generation and residential use) by flexible generation
of SNG, and providing clean water in water stressed areas by SWRO desalination. The flexibility
provided by the integrated scenario to the system is most useful in compensating seasonal fluctuations.
The additional electricity demand for 572 TWh
th
(58.5 bcm) of SNG and 9.7 billion m
3
of clean water
is covered by the RE resources available in Southeast Asia. The additional electricity requirement of
1006 TWh
el
for gas synthesis and SWRO desalination is met by installing an additional 310 GW of PV
and 140 GW of wind. Due to this, there is an increase in short term battery storage and a decrease
in gas storage as a consequence of the higher flexibility of the electrolyzer units. These units are
significantly increased by about 114 GW, equal to 96.6% compared to the area-wide scenario. As well,
Energies 2017,10, 583 18 of 25
area substantial decreases in gas turbine and biomass power plant capacities. The total benefit for
integrating the electricity, seawater desalination and industrial gas sectors is projected to be about 16 b
in absolute and 9.5% in relative terms for annual system cost. Other benefits due to integrating the
three sectors are a decrease in electricity demand by 149 TWh and electricity curtailment by 61 TWh.
The main benefit of integrating the three sectors is the decrease of LCOE by 20.3%, to 51.1
/MWh,
when compared to the area-wide open trade scenario without any sector integration. In addition,
the cost of desalinated water is affordable at 0.57
/m
3
for the Southeast Asia and Pacific region,
and the cost for synthetic gas is 95 /MWh.
The excess heat generated by the system as a byproduct of various processes such as biogas and
biomass CHP plants, waste-to-energy incinerators, gas turbines, electrolyzers and methanation plants
can be used to cover the heating demand in the industrial sector. In addition, the excess electricity
curtailed by the system can be converted to heat, stored in heat storage and utilized for heat demand. For
the area-wide open trade scenario, the usable heat generated is 325 TWh
th
per year, for the region-wide
scenario it is 356 TWh
th
per year, and for the integrated scenario it is 456 TWh
th
per year. The higher
usable heat in the integrated scenario is due to a higher absolute curtailment of electricity. The waste
heat generated as a byproduct of biomass and biogas plants is evenly distributed over the year.
PV prosumers play an important role in the power sector and influence the system. For the latter
the demand is assumed to be covered in a more centralized way. When the annualized costs are
compared, the more centralized 100% RE system is 3.6%, 3.7% and 3.7% lower than decentralized
system for the region-wide, country-wide and area-wide open trade scenarios, respectively. However,
potential positive effects at the distribution grid level and a lower risk level of power cuts have been
not taken into account. The additional cost for PV self-consumption is due to the different target
function for the prosumers. The minimum annual costs of electricity consumption are often reached
by the prosumers. For PV self-consumption to make an impact, its LCOE must be lower than the grid
electricity purchase price but it can be higher than the total system LCOE. In addition to prosumers’
higher electricity generation cost, there is a tendency to increase the cost of the system by installing
more flexible options, like low cost RE or more storage capacities, which induce a disturbance in
the system demand profile. However, the peak demand of the entire system is reduced by about 5%
(Figure 5), indicating that the highest cost hours in the system, which are mainly around noon, can be
reduced by PV prosumers.
For a decentralized system, the positive impact of A-CAES is observed on the system parameters
such as total LCOE, LCOS, storage losses and distribution of various storage technologies. In the case
of Southeast Asia, a region with low wind share and low seasonal variation, the output of A-CAES was
1.9% of the total storage output [
63
]. The reason for the low output is due to the availability of sunlight
all year around, such that batteries and PHS are used on a daily basis and followed by A-CAES and
PtG for seasonal variation [
63
]. In a centralized system, the benefit due to A-CAES is reduced due
to the transfer of electricity via grids being partly more economical than local storage technologies.
In Southeast Asia, batteries are still the least cost storage technology on a daily basis and PtG is the
least cost solution on a seasonal basis. As A-CAES lies in between daily and seasonal storage, it can be
substituted by the continental grids.
5.2. Comparision with Other Future Scneario Studies for Southeast Asia and Pacific Rim
The key results and conclusions of the various scenarios described in the Introduction are taken
here for comparison and discussion with the results of this study.
According to Blakers et al. [
6
] and Taggart et al. [
13
,
22
], transmission of electricity would
be beneficial from Australia to Southeast Asia, but the findings from this research contradict the
above authors’ expectations because these authors have not anticipated the low cost potential
of storage technologies against the cost of transmission of electricity from Australia to ASEAN
countries. Our findings suggest that local storage technologies can be a more cost effective option than
transmission of electricity over distances of thousands of kilometers.
Energies 2017,10, 583 19 of 25
The IEA recently published its “Southeast Asia Energy Outlook 2015” [
5
], which projected
a combined 4% share for solar PV and wind energy in the region for the year 2040. This is in drastic
contrast to the findings of this study. The final outcome of any future scenario result is based on
the input data and assumptions considered. The assumptions of the IEA for future solar PV and
wind costs are also at odds with a current trend of their fast decline, as again found for the latest
IEA WEO 2016 [
67
] summarized by Breyer [
68
]. Quite interesting are the IEA [
5
] year 2030 cost
assumptions for wind onshore (1700 USD/kW) and large-scale solar PV (1600 USD/kWp), which
are for the case of solar PV substantially higher than the respective 850
/kWp already achieved in
2015 and expected 470
/kWp in 2030 for European solar PV power plants [
69
]. This is a comparable
price for such large-scale solar PV power plants all around the world. Non-governmental organization
(NGOs), such as the Energy Watch Group [
70
], and also financial advisors such as Carbon Tracker [
71
]
and Bloomberg [
72
] state that the market assumptions of the IEA for solar PV and wind energy are
unrealistically low and conservative, mainly due to false assumptions for the growth pattern of these
two major RE technologies [
73
]. The IEA expectations of a 77% fossil fuel share in the electricity sector
for the year 2040 in Southeast Asia seem to be fully in conflict with the latest agreements at Conference
of Parties (COP) 21 in Paris [
74
], whereby a substantial reduction of greenhouse gas emissions till
the middle of the 21st century had been agreed. A recalculation of the IEA scenario for Southeast
Asia assuming 2015 prices for fossil fuels leads to a LCOE of the power mix of about 73 USD/MWh,
which is comparable to the 66
/MWh of the country-wide 100% RE scenario in this study. However,
the fossil-based mix includes a substantially higher risk, e.g., for stranded assets and further societal
costs such as health costs due to air pollution.
The technical feasibility of a 100% RE system has been studied by Elliston et al. [
19
,
21
] for Australia
(National Electricity Market region). The study points out that a 100% RE based system is a cost
effective option. This is in agreement with our findings, although the mix of technologies that will
power this system differs. According to Elliston et al., a 100% RE based system will be dominated by
wind energy with small contributions from PV. However, from our findings, the least cost installed mix
of technologies will be led by PV and closely followed by wind. Photovoltaics will play a major role in
Australia, due to the favorable climatic conditions and high full load hours. Wind and CSP with thermal
energy storage were found to be the least cost solution by Matthew and Patrick [
20
]. They mention that
the above combination can be commercially deployed on a large scale in Australia. The findings of this
paper suggest otherwise; wind will play an important role in the future for Australia, as will PV. This is
due to the dramatic decrease in the cost of PV systems and batteries, in contrast to CSP, which is also
indicated by Afanasyeva et al. [
75
]. According to Mason and Page [
14
], a 100% RE based system for
New Zealand will be based on hydro and followed by wind. Our findings are in agreement that the
system will involve hydro, but PV and wind will contribute equally in electricity generation.
For the ASEAN region, a 100% RE system will be based on PV as a major source according
to Hearps and Gilbert [
23
]. Our findings for the ASEAN region correlate with this conclusion as
PV will be the least cost option for powering the generation mix. According to Teske et al. [
7
],
the share of renewables in the electricity generation mix till 2030 could be 60% and by 2050 it could be
92%. Moreover, the installed capacity of renewables could reach 427 GW in 2030 and 1184 by 2050.
The comparable results obtained from this study indicate that a 100% RE based system is possible by
2030 with installed capacity of renewables of 722 GW for a centralized scenario.
Another study of the ASEAN region by Huber et al. [
24
] analyzes the cost optimal pathways
towards a sustainable electricity system. The analysis is performed on an hourly basis for 12 weeks,
with each week representing a month in a year. Our model goes further and analyses generation,
demand, transmission and storage for every unique hour of the year. The assumptions for various
technologies in Huber et al. are taken from IEA WEO 2013, which are rather conservative in comparison
to the assumptions in this study. The results obtained for an optimal generation mix according to
Huber et al. [
24
] for a zero carbon emissions scenario suggests that PV is a major source of electricity
followed by wind and hydro. It is also mentioned that the region’s high geothermal potential is
Energies 2017,10, 583 20 of 25
exploited, as it is a cost effective technology. Biomass will play an important role in balancing the
fluctuations. Due to the high deployment of PV, batteries will play a vital role in storing this energy
for later use. According to Huber et al. [
24
], grid connections will play an important role in a system
with a high share of renewables due to their intermittency. Moreover, the grid connections allow
the balancing of fluctuations across different regions through major export and import of electricity
between the ASEAN countries. In such a case, Vietnam is seen as a net exporter. The major power
trading lines are Myanmar West–Myanmar South, Vietnam–Cambodia (transport of offshore wind
power to the main ASEAN region), Jakarta–Sumatra and Myanmar–Thailand. These results from
a centralized scenario were compared with the alternative decentralized scenario. The conclusion was
that a cost optimal mix involving very high share of renewables and integration of different areas for
electricity trading are necessary to avoid large curtailment and higher costs of electricity. The above
results are in agreement with the results of this study with regards to electricity generation mix and
interconnections via grids being beneficial.
5.3. Discussion of the LCOE of Alternative Technologies
The results obtained for a 100% renewable energy based system for Southeast Asia and the Pacific
region can be compared with recent alternatives to non-renewable technology options in Europe such
as nuclear energy, natural gas and coal carbon capture and storage (CCS) [
76
]. These alternatives can
also serve to comply with the climate change mitigation policy for a low carbon based energy system.
However, the LCOE of alternatives as given in [
76
] are 112
/MWh for new nuclear (assumed for 2023 in
the UK and Czech Republic), 112
/MWh for gas CCS (assumed for 2019 in the UK, and 126
/MWh for
coal CCS (assumed for 2019 in the UK). In addition, a report published by the European Commission [
77
]
indicates that CCS technology will not be available till the year 2030, and a report by Citigroup questions
whether it will ever be profitable at all [
78
]. The findings in this paper indicate a scenario based on 100%
RE is possible and cheaper in cost than these higher risk options, which still have many disadvantages
compared to renewable resources. These disadvantages include nuclear proliferation risk, nuclear
melt-down, a lack of a solution to nuclear waste disposal, leftover CO
2
emissions from power plants with
CCS technology, health risks due to heavy metal emissions from coal fired power plants, and diminishing
fossil fuel reserves. Another commonly mentioned option, nuclear fission, has limitations similar to
those mentioned above. Moreover, the financial, and human research and development resources spent
towards it will not solve the energy problems in the world [
79
]. The above-mentioned alternative options
do not satisfy the criteria for low cost, fully sustainable pathways for the future.
6. Conclusions
Enough power can be generated from the RE technologies to cover all the electricity demand for
the year 2030 on a cost level of 51–66
/MWh
el
depending on geographical and sectorial integration.
The cost parameter range when compared to non-renewable energy resources is significantly lower and
the intermittency of renewables is effectively stabilized by grids and storage technologies to provide
the hourly demand of electricity. In addition, the cost of primary energy generation is between 66–72%
of the total cost depending on the scenario, which ensures that demand is always met at a modest cost.
In addition to electricity demand, it is possible to cover the gas demand in the industrial sector by the
PtG technology. The demand for heating in the industrial and residential sectors may be at least partly
covered by the excess heat generated as a by-product of SNG generation and conversion of curtailed
electricity. For all the scenarios, PV plays a major role followed by biomass and wind energy in all
the regions apart from Australia, where PV and wind play an important role. For the region-wide
scenario, the storage requirements are mainly based on batteries. The role of other storage technologies,
especially A-CAES, has a vital role in the region-wide scenario as a mid-term storage between batteries
and PtG particularly in areas of high wind share and high seasonal variation. The HVDC transmission
grid plays a role in the trading of electricity in the ASEAN countries, where trading is more cost
competitive than local storage technologies available. However, in some cases, due to long distances,
Energies 2017,10, 583 21 of 25
local storage technologies are more cost competitive than transmission of electricity. This is also
observed in the case of A-CAES, where grid integration reduces the economic benefit of this particular
storage technology but other storage technologies such as batteries and PtG are still required. Due to
this, the system configurations for a region-wide and area-wide open trade scenario are very similar.
A slight increase of 3–4% in the total cost of electricity because of PV self-consumption is due to the
utilization of solar electricity and in particular respective batteries for self-consumption at a higher cost
level. In addition, disturbances in the system due to the excess electricity generated from prosumer
increases system’s need for additional flexibility, while reducing the most costly peak hours in the year.
In the case of an integrated scenario, it was found that seasonal SNG storage is largely substituted by
industrial SNG generation for the electricity sector. In the case of energy deficit, instead of using gas
turbines the system restricts SNG production as a major source of flexibility.
More research is required that investigates how to utilize the waste heat generated in the system
and to better understand a fully integrated renewable energy system in Southeast Asia and the Pacific.
However, this research indicates that a 100% RE system is reachable in Southeast Asia and the Pacific,
and more cost competitive than a nuclear-fossil fuel option.
Supplementary Materials:
Supplementary Materials are available online at www.mdpi.com/1996-1073/10/5/583/s1.
Acknowledgments:
The authors gratefully acknowledge the public financing of Tekes, the Finnish Funding
Agency for Innovation, for the “Neo-Carbon Energy” project under the number 40101/14. The first author would
like to thank Fortum Foundation for the valuable scholarship. The authors would like to thank Michael Child
for proofreading.
Author Contributions:
Ashish Gulagi collected the input data, performed the research and simulations, generated
the results, analyzed the results, and wrote the manuscript. Dmitrii Bogdanov did the coding for the model
used in this research. Christian Breyer framed the research questions and scope of the work, checked the results,
facilitated discussions, and reviewed the manuscript.
Conflicts of Interest:
The authors declare no conflict of interest. The founding sponsors had no role in the design
of the study; in the collection, analyses, or interpretation of data; in the writing of the manuscript, and in the
decision to publish the results.
Abbreviations
A-CAES Adiabatic compressed air energy storage
ASEAN Association for South East Nations
Capex Capital expenditure
CCGT Combined cycle gas turbine
CCS Carbon capture and storage
CSP Concentrating solar thermal power
FLH Full load hours
HVDC High-voltage direct current
IEA International Energy Agency
NEM National Electricity Market
LCOC Levelized cost of curtailment
LCOE Levelized cost of electricity
LCOG Levelized cost of gas
LCOS Levelized cost of storage
LCOT Levelized cost of transmission
OCGT Open cycle gas turbine
Opex Operational expenditure
PHS Pumped hydro storage
PtG Power-to-gas
RE Renewable energy
SWRO Seawater reverse osmosis
TES Thermal energy storage
WACC Weighted average cost of capital
Energies 2017,10, 583 22 of 25
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... Energy transition studies utilising high shares of renewable and sustainable energy resources for the Philippines has been gaining momentum in recent years. While most of these studies focus on the transition of the power sector with scenarios utilising some share of fossil fuels as a backup, Gulagi et al. [59,60], Jacobson et al. [10] and Teske [11] offer scenarios ranging for various sectors towards 100% renewable energy for the future. Jacobson et al. [10] offer pathways towards 100% RE for the Philippines utilising the abundant solar, wind and hydropower resources. ...
... Jacobson et al. [10] offer pathways towards 100% RE for the Philippines utilising the abundant solar, wind and hydropower resources. Gulagi et al. [59] did an overnight 100% RE scenario excluding the heat and transport sectors for the year 2030 for Southeast Asia and the Pacific Rim based on different levels of interconnection between the countries. The Philippines was modelled as an individual node having High Voltage Direct Current (HVDC) connection to Indonesia. ...
... As discussed, the capital expenditure costs are rather a one-time investment and there is less risk of price volatility as compared to fossil fuels. The power sector is projected to reach zero GHG emissions first by 2035 or even as early as in 2030 as reported by Gulagi et al. [59], based on a comprehensive study with solar PV and batteries playing an important role, confirming the analysis of this study. The heat and transport sector follow next in leading to a complete elimination of GHG emissions from all the sectors. ...
Article
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Transition towards sustainable energy systems is of utmost importance to avert global consequences of climate change. Within the framework of the Paris Agreement and Marrakech Communique, this study analyses an energy transition pathway utilising renewable resources for the Philippines. The transition study is performed from 2015 to 2050 on a high temporal and spatial resolution data, using a linear optimisation tool. From the results of this study, technically, a 100% fossil free energy system in 2050 is possible, with a cost structure comparable to an energy system in 2015, while having zero greenhouse gas emissions. Solar PV as a generation and batteries a as storage technology form the backbone of the energy system during the transition. Direct and indirect electrification across all sectors would result in an efficiency gain of more than 50% in 2050, while keeping the total annual investment within 20-55 b€. Heat pumps, electrical heating, and solar thermal technologies would supply heat, whereas, direct electricity and synthetic fuels would fuel the energy needs of the transport sector. The results indicate that, indigenous renewable resources in the Philippines could power the demand from all energy sectors, thereby, bringing various socioeconomic benefits.
... With rapid economic growth in most of these countries, the need for energy is ever increasing and some of the more developed countries have a high rate of consumption to sustain. In this context, the total electricity consumption that is around 1208 TWh in 2015, is estimated to soar up to 4222 TWh by 2050 (IEA, 2016;Gulagi et al., 2017). Renewables have grown rapidly as a power source across Southeast Asia, with their installed capacity at around 15 GW in 2016 (IRENA, 2018b). ...
Thesis
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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.
... When compared with the amount of research for the developed countries, there is a stark difference, with most research in the last decades focussed on developed countries and regions [10]. However, acknowledging this fact the LUT Energy System Transition Model has been applied for many developing countries such as Bangladesh [31], India [32], Pakistan [33], Nepal and Bhutan [34] along with SAARC [35], the Philippines [36], Indonesia [37], and Southeast Asia [38], further countries in Africa such as Cameroon [39], Ethiopia [40], Ghana [41], Nigeria [42], West Africa [43], and sub-Saharan Africa [44,45]. Further, North Africa and Middle East [46] and Morocco [47], Algeria [47], Jordan [48] and Iran [49], as well as the South American countries of Bolivia [50] and Chile [51] and South America [52] have been explored. ...
Article
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This is a discussion and response to “Global 100% energy transition by 2050: A fiction in developing economies?” authored by Anthony Afful-Dadzie and published in Joule 5 (2021) 1634–1643. The preview has raised concerns around the feasibility of energy transitions towards 100% renewable energy and sustainable technologies in developing economies, after examining the article Bogdanov et al. (2021) in Afful-Dadzie (2021). Although, the author has rightly pointed out the disparity in the recent growth of renewable energy across the developed and developing countries of the world, along with highlighting a pertinent issue of ‘availability of finance’ for energy transitions across developing countries, the preview fails to contextualise the issue of financing energy transitions, in particular across developing countries, and has trivialised complex and cumbersome cost optimal energy transition modelling with vague and unscientific illustrations. In response, the authors of Bogdanov et al. (2021) have contextualised, clarified and confuted the issues raised in Afful-Dadzie (2021).
... Emissions were not considered in that study. Gulagi et al. [20] performed a cost optimization of a fully renewable energy system for Southeast Asia and the Pacific Rim. The authors analyzed the costs of the system, but not its emissions. ...
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This paper aims to evaluate the life cycle greenhouse gas (GHG) emissions of importing electrical power into Singapore, generated from a large-scale solar photovoltaic (PV) power plant in Australia, through a long-distance subsea high-voltage direct current (HVDC) cable. A cost optimization model was developed to estimate the capacities of the system components. A comprehensive life cycle assessment model was built to estimate emissions of manufacturing and use of these components. Our evaluation shows that, for covering one fifth of Singapore’s electrical energy needs, a system with an installed capacity of 13GWPV, 17 GWh battery storage and 3.2GW subsea cable is required. The life cycle GHG emissions of such a system are estimated to be 110gCO2eq/kWh, with the majority coming from the manufacturing of solar PV panels. Cable manufacturing does not contribute largely toward GHG emissions. By varying full-load hours and cable lengths, it was assessed that sites closer to Singapore might provide the same energy at same/lower carbon footprint and reduced cost, despite the lower insolation as compared to Australia. However, these sites could cause greater emissions from land use changes than the deserts of Australia, offsetting the advantages of a shorter HVDC cable.
... Consequently, the interannual variability in renewable energy resources can be effectively captured, together with the weather events which occur occasionally with extremely low availability of renewable energy supply. In comparison, Gulagi et al. [32], Bogdanov et al. [5] optimised the 100% renewable electricity systems based on one year's energy data, while Huber et al. [33] only modelled 12 weeks with each week representing a month of the year. The future electricity demand is projected according to 3 MWh (low), 6 MWh (medium) and 9 MWh (high) per capita of electricity consumption, which represent 2-fold, 4-fold and 7-fold increases from the 2018 electricity demand, respectively. ...
Article
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Rapid increases in electricity consumption in Southeast Asia caused by rising living standards and population raise concerns about energy security, affordability and environmental sustainability. In this study, the role of short-term off-river energy storage (STORES) in supporting 100% renewable electricity in Southeast Asia is investigated. Large-scale integration of off-river, closed-loop pumped hydro storage is a new approach to providing system flexibility facilitating high penetration of variable renewable energy in electricity systems. The features of STORES include large storage potential, high technology maturity and a long service life. Energy generation, storage and transmission are co-optimised based on long-term, high-resolution chronological energy data. A comparative analysis is undertaken between the scenarios with and without an intercontinental Asia-Pacific Super Grid. The results show that, with support provided by STORES, the Southeast Asian electricity industry can achieve very high penetration (78%-97%) of domestic solar and wind energy resources. The levelised costs of electricity range from 55-115 U.S. dollars per megawatt-hour based on 2020 technology costs. In the Super Grid scenarios, the costs change by -4% to +7% while the storage requirements reduce by 50%-89%. Renewable energy supported by STORES can be a cost�effective solution for Southeast Asia’s energy transition, delivering long-term, substantial environmental benefits.
... a. Environmental: climate change and risks resources scarcity (Yusuf & Francisco, 2009), renewable energy development (Gulagi et al., 2017;Kennedy, 2018), pollution and natural disaster (Haibo et al., 2019), food sustainability (Hirabayashi et al., 2013); b. Social: health and safety standard in business (Pingle, 2012;Siriruttanapruk & Anantagulnathi, 2004) and consumer protection (Wang et al., 2008); c. ...
Article
This work is among the first studies to review the Morgan Stanley Capital International (MSCI) ESG Leaders Index in Asian countries and other emerging markets, such as Brazil, China, and Russia. The relationships among gross domestic product (GDP), human development index (HDI), and a set of key indicators are the fundamental argument of this study. By applying 2SLS estimation from 2010 to 2018, this research examines the connection between environmental, social, governance (ESG) index, GDP growth, and HDI from nine countries as rated in the MSCI ESG Index. The objective is to test whether the index can be efficiently utilized to justify the notion that the adoption of ESG principles can positively influence sustainable development and inclusive growth. The post estimations reveal close relationships between the ESG index and GDP growth. However, the index is not an effective instrument for measuring the connection between HDI‐ESG because it has not yet had a direct effect on HDI. With this result, the index can be utilized to measure the connections with and investments made by countries and corporations for sustainable development.
... For instance, the grid transmission lines in the Greater Mekong Region have already been connected with China's Yunnan Providence under China's Belt and Road Initiative [24]. There are also potentials and possibilities to establish interconnections with Australia [74] and other Pacific Rim region across the sea [75]. If the interconnections are duly established with its neighboring countries and regions, the economics and flexibility of the ASEAN power grid system could be greatly improved, and new windows for development of solar PV power can be opened up. ...
Article
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The Association of Southeast Asian Nations (ASEAN) has experienced rapid social and economic development in the past decades, while energy shortage, environmental pollution, and climate change are the factors that prevent a sustainable development process. Deployment of solar photovoltaic (PV) power is one of the effective alternatives to overcome the above barriers and assist ASEAN to achieve the aspirational target of 23% renewable energy (RE) in the total primary energy supply (TPES). In this study, SWOT analysis is adopted to analyze the internal strengths and weaknesses and the external threats and opportunities tightly related to the development of solar PV power in ASEAN countries. Through the SWOT analysis, great potential for the development of solar PV power in ASEAN is found. As long as appropriate policies are implemented and proper actions are taken, huge space for deployment of solar PV power can be expected. Based on the SWOT analysis, countermeasures that emphasize further deployment of solar PV power in ASEAN countries are put forward. The tactics include arousing people’s awareness of a sustainable development process, government issue coherence and stable incentive policies, fostering a solar PV industry chain and master key technology, and seek opportunities via an international cooperation.
Article
Globally, more than 740 million people live on islands which are often seen as ideal environments for the development of renewable energy systems. Hereby, they play the role to demonstrate technical solutions as well as political transition pathways of energy systems to reduce greenhouse gas emissions. The growing number of articles on 100% renewable energy systems on islands is analyzed with a focus on technical solutions for transition pathways. Since the first “100% renewable energy systems on islands”‐article in a scientific journal in 2004, 97 articles handling 100% renewable energy systems on small islands were published and are reviewed in this article. In addition, a review on 100% renewable energy systems on bigger island states is added. Results underline that solar PV as well as wind are the main technologies regarding 100% RES on islands. Not only for the use of biomass but for all RES area limitation on islands needs to be taken more seriously, based on full energy system studies and respective area demand. Furthermore, it is shown that there is still not the same common sense in the design approach including and starting at the energy needs as well as on multi‐sectoral approach. The consideration of maritime transport, aviation, cooling demands, and water systems beyond seawater desalination is only poorly considered in existing studies. Future research should also focus on developing pathways to transform the existing conventional infrastructure stepwise into a fully renewable system regarding also the interconnections with the mainland and neighboring islands. This article is categorized under: Policy and Economics > Green Economics and Financing Energy Systems Economics > Economics and Policy Energy Systems Analysis > Economics and Policy Energy Systems Analysis > Systems and Infrastructure Ninety‐seven articles handling 100% renewable energy systems on small islands are reviewed, most of them belonging to Europe while further regions are underrepresented in scientific literature.
Thesis
Global warming is one of the main effects of humanmade climate change. It is common sense that direct emission-free renewable energy must be integrated on a large scale into our energy systems to limit the earth’s temperature rise. The integration of fluctuating renewable electricity sources presents a major challenge for future energy systems as the residual load curve will be characterized by high fluctuations, significant ramp rates and the need for peak power coverage. Utility-scale energy storage technologies are likely to be required to ensure a reliable and affordable energy supply. In order to achieve deep decarbonization all sectors (electricity, heat, transport, etc.) must be considered. The heating and cooling sector is seen as an important lever to balance fluctuations and increase the share of renewable energy in all sectors. For this reason, hybrid energy storage is introduced within this work. It is a technological option at the intersection of multiple sectors by combining thermal and/or thermo-mechanical and/or chemical conversion and energy storage units to large-scale energy storage solutions. In contrast to power to power energy storages like batteries, hybrid energy storages make it possible to address demands of the electric and heating/cooling sector. Various technologies for energy storage can be found in literature. These technologies are sorted if they already fulfill the hybrid definition made within this work or if they at least could be used in a hybrid way. For this reason, a strategy for hybridization is defined. Different hybrid or hybridizable energy storages based on different physical mechanisms are the fundamental base of this work. They all differ in technical maturity and the underlying performance estimations typically rely on varying boundary conditions and assumptions. This makes storage parameters in terms of roundtrip efficiencies and specific cost highly incomparable. By combining thermodynamic calculations with cost estimation, a comparable database of storage parameters in terms of roundtrip efficiencies and cost data is created. Technologies proposed in literature also serve as pool for modifications. Rapidly changing boundary conditions in energy systems worldwide create unclear requirements towards energy storage technologies. Sometimes, an investment cost-optimized storage could be better than an efficiency-optimized one and vice versa. In order to assess the potential of hybrid energy storages, energy system design is applied. The focus is on urban energy systems since the extraction of heat and cold from hybrid storages can address district heating and cooling systems. For this reason, a generic model for the design and optimization of urban energy systems is developed. Based on an archetype approach, the cities Barcelona, Jakarta, Buenos Aires, Toronto, Dubai and Hamburg are selected – all with different loads (electricity and heating, electricity and cooling or electricity and heating and cooling) and different local boundary conditions, e.g. different potentials for the implementation of renewable energy as they are located in different climate zones. In order to create a powerful model, the hybrid energy storages are combined with a large number of state-of-the-art energy generation, conversion and storage technologies, e.g. renewable and fossil power generation, heat pumps, batteries, thermal storages, as benchmark. A linear programming optimization procedure is applied to derive energy systems that allow the most cost-effective supply in terms of electric and thermal demands to the cities. A special focus is on decarbonization as cost-optimal system configurations are derived under direct carbon emission constraints. The results indicate that hybrid energy storages are not part of cost-optimal energy systems without carbon constraints but generate an impact at medium and high decarbonization rates. Total expenditures for the energy supply of all cities decrease on average by around 1 % at a decarbonization rate of 80 % and by 16 % at a decarbonization rate of 100 %. The deployment of hybrid storages especially has an impact on technologies for large-scale heat and cold generation. Sensitivities towards specific cost and the type of implementation show the robustness of the calculated solutions.
Article
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The Paris Agreement points out that countries need to shift away from the existing fossil-fuel-based energy system to limit the average temperature rise to 1.5 or 2 °C. A cost-optimal 100% renewable energy based system is simulated for East Asia for the year 2030, covering demand by power, desalination, and industrial gas sectors on an hourly basis for an entire year. East Asia was divided into 20 sub-regions and four different scenarios were set up based on the level of high voltage grid connection, and additional demand sectors: power, desalination, industrial gas, and a renewable-energy-based synthetic natural gas (RE-SNG) trading between regions. The integrated RE-SNG scenario gives the lowest cost of electricity (€52/MWh) and the lowest total annual cost of the system. Results contradict the notion that long-distance power lines could be beneficial to utilize the abundant solar and wind resources in Australia for East Asia. However, Australia could become a liquefaction hub for exporting RE-SNG to Asia and a 100% renewable energy system could be a reality in East Asia with the cost assumptions used. This may also be more cost-competitive than nuclear and fossil fuel carbon capture and storage alternatives.
Article
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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.
Article
This paper presents the geological resource potential of the compressed air energy storage (CAES) technology worldwide by overlaying suitable geological formations, salt deposits and aquifers. For this study, the world is divided into 145 regions, which are aggregated to 9 major regions. The potential of CAES in each region is assessed and a relevant map is provided. Three constraints have been implemented, allowing for 1%, 5% and 10% of the selected area to be considered for CAES. Among all major regions, in the most conservative constraint (1% of the total area), North America is the leader with 0.26% suitability of its total area, followed by Sub-Saharan Africa and South America at 0.20% and 0.19%, respectively. A sensitivity analysis is implemented to evaluate the validity and reliability of the results. Three scenarios are considered: Optimistic, Moderate and Pessimistic. Underground natural gas storage data for the US is used due to freely and publicly available data. The natural gas storage site is assumed to have the same structure as CAES. The sensitivity analysis shows that the accuracy of the findings lie in the range of 66-85% and 63-82%, depending on the scenarios and reservoir types. The results clearly reveal that CAES is a promising energy storage technology for electricity supply in most of the regions. This research presents the groundwork to identify the untapped potential of CAES, which can be also utilized for the second generation of CAES such as adiabatic CAES and isothermal CAES.
Article
Power systems for South and Central America based on 100% renewable energy (RE) in the year 2030 were calculated for the first time using an hourly resolved energy model. The region was subdivided into 15 sub-regions. Four different scenarios were considered: three according to different high voltage direct current (HVDC) transmission grid development levels (region, country, area-wide) and one integrated scenario that considers water desalination and industrial gas demand supplied by synthetic natural gas via power-togas (PtG). RE is not only able to cover 1813 TWh of estimated electricity demand of the area in 2030 but also able to generate the electricity needed to fulfil 3.9 billion m 3 of water desalination and 640 TWh LHV of synthetic natural gas demand. Existing hydro dams can be used as virtual batteries for solar and wind electricity storage, diminishing the role of storage technologies. The results for total levelized cost of electricity (LCOE) are decreased from 62 €/MWh for a highly decentralized to 56 €/MWh for a highly centralized grid scenario (currency value of the year 2015). For the integrated scenario, the levelized cost of gas (LCOG) and the leve-lized cost of water (LCOW) are 95 €/MWh LHV and 0.91 €/m 3 , respectively. A reduction of 8% in total cost and 5% in electricity generation was achieved when integrating desalination and power-to-gas into the system.
Article
Global power plant capacity has experienced a historical evolution, showing noticeable patterns over the years: continuous growth to meet increasing demand, and renewable energy sources have played a vital role in global electrification from the beginning, first in the form of hydropower but also wind energy and solar photovoltaics. With increasing awareness of global environmental and societal problems such as climate change, heavy metal induced health issues and the growth related cost reduction of renewable electricity technologies, the past two decades have witnessed an accelerated increase in the use of renewable sources. A database was compiled using major accessible datasets with the purpose of analyzing the composition and evolution of the global power sector from a novel sustainability perspective. Also a new sustainability indicator has been introduced for a better monitoring of progress in the power sector. The key objective is to provide a simple tool for monitoring the past, present and future development of national power systems towards sustainability based on a detailed global power capacity database. The main findings are the trend of the sustainability indicator projecting very high levels of sustainability before the middle of the century on a global level, decommissioned power plants indicating an average power plant technical lifetime of about 40 years for coal, 34 years for gas and 34 years for oil-fired power plants, whereas the lifetime of hydropower plants seems to be rather unlimited due to repeated refurbishments, and the overall trend of increasing sustainability in the power sector being of utmost relevance for managing the environmental and societal challenges ahead. To achieve the 2 °C climate change target, zero greenhouse gas emissions by 2050 may be required. This would lead to stranded assets of about 300 GW of coal power plants already commissioned by 2014. Gas and oil-fired power plants may be shifted to renewable-based fuels. Present power capacity investments have already to anticipate these environmental and societal sustainability boundaries or accept the risk of becoming stranded assets.
Conference Paper
Indonesia is an archipelago country consisting of five major islands and scattered of approximately 17,000 smaller islands. It is also the fourth most populous country in the world and has relatively high energy demand, especially for electricity. The Java-Bali system is the largest electricity system and the highest electricity demand in Indonesia but with a scarce energy resource. Meanwhile, the Sumatra system has a lower electricity demand but an abundant of available energy resources. Thus, in order to increase the national electrification ratio and the power supply in Java-Bali system, a ± 500 kV high voltage direct current (HVDC) system will be operated in 2018 to transfer 3000 MW from Sumatra island to Java Island through 504 km dc transmission line (including 40 km sea-cable) by a conventional type, i.e. Line Commutated Converter (LCC). This 3000 MW is produced from 6×600 MW coal power plant located in South Sumatra. The rest of this power will be transmitted to the Sumatra System.
Article
Globally, small islands below 100,000 inhabitants represent a large number of diesel based mini-grids. With volatile fossil fuel costs which are most likely to increase in the long-run and competitive renewable energy technologies the introduction of such sustainable power generation system seems a viable and environmental friendly option. Nevertheless the implementation of renewable energies on small islands is quite low based on high transaction costs and missing knowledge according to the market potential.
Conference Paper
In this work, a 100% renewable energy (RE)-based energy system for the year 2030 for Southeast Asia and the Pacific Rim 1 , and Eurasia was prepared and evaluated and various impacts of adiabatic compressed air energy storage (A-CAES) were researched on an hourly resolution for one year. To overcome the intermittency of RE sources and guarantee regular supply of electricity, energy sources are complemented by five energy storage options: batteries, pumped hydro storage (PHS), thermal energy storage (TES), (A-CAES) and power-togas (PtG). In a region-wide scenario the energy system integration is within a sub-region of the individual large areas of Southeast Asia and Eurasia. In this scenario simulation were performed with and without A-CAES integration. For Southeast Asia and Eurasia, the integration of A-CAES has an impact on the share of a particular storage used and this depends on the seasonal variation in RE generation, the supply share of wind energy and demand in the individual areas. For the region-wide scenario for Southeast Asia (region with low seasonal variation and lower supply share of wind energy) the share of A-CAES output was 1.9% in comparison to Eurasia (region with high seasonal variation and a high supply share of wind energy) which had 28.6%. The other impact which was observed was the distribution of the storage technologies after A-CAES integration, since battery output and PtG output were decreased by 72.9% and 21.6% (Eurasia) and 5.5% and 1.6% (Southeast Asia), respectively. However, a large scale grid integration reduces the demand for A-CAES storage drastically and partly even to zero due to substitution by grids, which has been only observed for A-CAES, but not for batteries and PtG. The most valuable application for A-CAES seems to be in rather decentralized or nationwide energy system designs and as a well-adapted storage for the typical generation profiles of wind energy.
Article
This study demonstrates how seawater reverse osmosis (SWRO) plants, necessary to meet increasing future global water demand, can be powered solely through renewable energy. Hybrid PV–wind–battery and power-to-gas (PtG) power plants allow for optimal utilisation of the installed desalination capacity, resulting in water production costs competitive with that of existing fossil fuel powered SWRO plants. In this paper, we provide a global estimate of the water production cost for the 2030 desalination demand with renewable electricity generation costs for 2030 for an optimised local system configuration based on an hourly temporal and 0.45° × 0.45° spatial resolution. The SWRO desalination capacity required to meet the 2030 global water demand is estimated to about 2374 million m3/day. The levelised cost of water (LCOW), which includes water production, electricity, water transportation and water storage costs, for regions of desalination demand in 2030, is found to lie between 0.59 €/m3–2.81 €/m3, depending on renewable resource availability and cost of water transport to demand sites. The global system required to meet the 2030 global water demand is estimated to cost 9790 billion € of initial investments. It is possible to overcome the water supply limitations in a sustainable and financially competitive way.
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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.