Long-Term Hydrocarbon Trade Options for the Maghreb Region and Europe—Renewable Energy Based Synthetic Fuels for a Net Zero Emissions World

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DOI: 10.3390/su9020306
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Abstract
Concerns about climate change and increasing emission costs are drivers for new sources of fuels for Europe. Sustainable hydrocarbons can be produced synthetically by power-to-gas (PtG) and power-to-liquids (PtL) facilities, for sectors with low direct electrification such as aviation, heavy transportation and chemical industry. Hybrid PV–Wind power plants can harvest high solar and wind potentials of the Maghreb region to power these systems. This paper calculates the cost of these fuels for Europe, and presents a respective business case for the Maghreb region. Calculations are hourly resolved to find the least cost combination of technologies in a 0.45⁰ x 0.45⁰ spatial resolution. Results show that, for 7% weighted average cost of capital (WACC), renewable energy based synthetic natural gas (RE-SNG) and RE-diesel can be produced in 2030 for a minimum cost of 76 €/MWh,HHV (0.78 €/m3 SNG) and 88 €/MWh,HHV (0.85 €/L), respectively. While in 2040, these production costs can drop to 66 €/MWh,HHV (0.68 €/m3 SNG) and 83 €/MWhHHV (0.80 €/L), respectively. Considering access to a WACC of 5% in a de-risking project, oxygen sales and CO2 emissions costs, RE-diesel can reach fuel-parity at crude oil prices of 101 and 83 USD/bbl in 2030 and 2040, respectively. Thus, RE-synthetic fuels could be produced to answer fuel demand and remove environmental concerns in Europe at an affordable cost.
sustainability
Article
Long-Term Hydrocarbon Trade Options for the
Maghreb Region and Europe—Renewable Energy
Based Synthetic Fuels for a Net Zero Emissions World
Mahdi Fasihi *, 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: mahdi.fasihi@lut.fi; Tel.: +358-44-912-3345
Academic Editor: Arnulf Jäger-Waldau
Received: 20 November 2016; Accepted: 15 February 2017; Published: 19 February 2017
Abstract:
Concerns about climate change and increasing emission costs are drivers for new sources
of fuels for Europe. Sustainable hydrocarbons can be produced synthetically by power-to-gas (PtG)
and power-to-liquids (PtL) facilities, for sectors with low direct electrification such as aviation, heavy
transportation and chemical industry. Hybrid PV–Wind power plants can harvest high solar and
wind potentials of the Maghreb region to power these systems. This paper calculates the cost of these
fuels for Europe, and presents a respective business case for the Maghreb region. Calculations are
hourly resolved to find the least cost combination of technologies in a 0.45
×
0.45
spatial resolution.
Results show that, for 7% weighted average cost of capital (WACC), renewable energy based synthetic
natural gas (RE-SNG) and RE-diesel can be produced in 2030 for a minimum cost of 76
/MWh
HHV
(0.78
/m
3SNG
) and 88
/MWh
HHV
(0.85
/L), respectively. While in 2040, these production costs
can drop to 66
/MWh
HHV
(0.68
/m
3SNG
) and 83
/MWh
HHV
(0.80
/L), respectively. Considering
access to a WACC of 5% in a de-risking project, oxygen sales and CO
2
emissions costs, RE-diesel
can reach fuel-parity at crude oil prices of 101 and 83 USD/bbl in 2030 and 2040, respectively. Thus,
RE-synthetic fuels could be produced to answer fuel demand and remove environmental concerns in
Europe at an affordable cost.
Keywords:
hybrid PV–Wind; power-to-gas (PtG); power-to-liquids (PtL); liquefied natural gas (LNG);
economics; fuel-parity; Maghreb region; Europe
1. Introduction
The planet is facing a dramatic climate change problem [
1
] and fossil fuel-based CO
2
emissions
are a limiting constraint for usage of fossil fuels in the long-term [
2
,
3
]. In the past years, voluntary
and mandatory regulations have been set to limit fossil fuel emissions at different levels. Based on the
COP21 Paris agreement, some certain countries, if not all, have to aim to reach a net zero emissions
system by 2050 [
4
]. This means, in these countries, fossil fuel consumption could be completely banned,
in particular since natural negative emissions such as growing forests are very limited and carbon
capture and storage (CCS) technology is high in cost and risky [
5
]. At the very least, this will result in
drastic reductions in the consumption of fossil fuels. Europe has been a leader for this trend in the last
decade and is expected to remain as one of the first places for the implementation of new solutions.
To reach the goal of net zero emissions, fossil fuel-based energy demand could be mainly
replaced by renewable electricity (RE). However, there are sectors such as aviation, shipping, heavy
transportation and non-energetic use of fossil fuels for which hydrocarbons cannot be replaced by
electricity easily, or physically not at all. Biofuel production is faced with resource limitations and
conflicts with food production and, therefore, offers no substantial substitute [
6
,
7
]. Net zero emissions
Sustainability 2017,9, 306; doi:10.3390/su9020306 www.mdpi.com/journal/sustainability
Sustainability 2017,9, 306 2 of 24
could be achieved by a recarbonization of the energy system, whereby carbon from fossil sources
is replaced by that which is created synthetically and sustainably, by the aid of RE. These RE-based
fuels are carbon neutral and can be used in the current fossil fuel-based infrastructure. There are
several technical options to produce hydrocarbon fuels based on hybrid PV–Wind power plants for the
transport and mobility sector: mainly RE-power-to-gas (PtG) [
8
], liquefied natural gas (LNG) based on
RE-PtG [
9
], and RE-power-to-liquids (PtL) [
10
]. Figure 1illustrates a very simplified version of these
value chains.
Sustainability 2017, 9, 306 2 of 24
could be achieved by a recarbonization of the energy system, whereby carbon from fossil sources is
replaced by that which is created synthetically and sustainably, by the aid of RE. These RE-based
fuels are carbon neutral and can be used in the current fossil fuel-based infrastructure. There are
several technical options to produce hydrocarbon fuels based on hybrid PV–Wind power plants for
the transport and mobility sector: mainly RE-power-to-gas (PtG) [8], liquefied natural gas (LNG)
based on RE-PtG [9], and RE-power-to-liquids (PtL) [10]. Figure 1 illustrates a very simplified version
of these value chains.
Figure 1. The hybrid PV–Wind-(PtG, PtG–LNG, and PtL) value chain (very simplified).
However, either Europe may not have the RE-based power potential to answer this demand due
to area limitations, or the final production cost could be too expensive. The Maghreb region (Algeria,
Libya, Mauritania, Morocco, Tunisia and Western Sahara), with a high potential of solar energy and,
to a lesser degree, wind power, can act as a carbon neutral oil well in the vicinity of Europe which
can export a wide range of carbon neutral hydrocarbons for the least transportation cost. RE-SNG
can be injected into the European gas grid through the natural gas (NG) pipelines connecting the
Maghreb region to Southern Europe or liquefied into LNG and shipped to Northern Europe. RE-
diesel and RE-jet fuel can be also shipped to European ports. This article investigates the production
potential of these approaches and the corresponding cost, in 2030 and 2040, based on Maghreb
region’s solar and wind potential. The article is structured into the following sections: Materials and
Methods, Results, Discussion and Conclusions.
2. Materials and Methods
The methodology used in this article for the PtG–LNG and PtL value chains is fully explained
in Fasihi et al. [9] and Fasihi et al. [10], respectively. As a summary, an updated version of the main
topics has been reviewed here.
The RE-PtG–LNG simplified value chain is illustrated in Figure 2. The main components are:
hybrid PV–Wind power plants, electrolyser and methanation plants, CO
2
from direct air capture
units, liquefaction to LNG, LNG shipping, and regasification. Electrolyser and methanation plants
are coupled and will work simultaneously and with an SNG storage system; the liquefaction plant
can run as base load. To have a sustainable energy system with carbon neutral products, atmospheric
CO
2
is used, which is independent of the location. The output heat of the electrolysis and methanation
is used to fulfill the heat demand of the CO
2
capture plant, which increases the overall efficiency of
the system. The water demand is supplied by seawater reverse osmosis (SWRO) desalination and the
recycled water from the methanation process. As a case study, Finland has been chosen as the long
distance market for SNG, where the LNG value chain (liquefaction, shipping and regasification) cost
has been applied.
Figure 1. The hybrid PV–Wind-(PtG, PtG–LNG, and PtL) value chain (very simplified).
However, either Europe may not have the RE-based power potential to answer this demand due
to area limitations, or the final production cost could be too expensive. The Maghreb region (Algeria,
Libya, Mauritania, Morocco, Tunisia and Western Sahara), with a high potential of solar energy and, to
a lesser degree, wind power, can act as a carbon neutral oil well in the vicinity of Europe which can
export a wide range of carbon neutral hydrocarbons for the least transportation cost. RE-SNG can be
injected into the European gas grid through the natural gas (NG) pipelines connecting the Maghreb
region to Southern Europe or liquefied into LNG and shipped to Northern Europe. RE-diesel and
RE-jet fuel can be also shipped to European ports. This article investigates the production potential of
these approaches and the corresponding cost, in 2030 and 2040, based on Maghreb region’s solar and
wind potential. The article is structured into the following sections: Materials and Methods, Results,
Discussion and Conclusions.
2. Materials and Methods
The methodology used in this article for the PtG–LNG and PtL value chains is fully explained in
Fasihi et al. [
9
] and Fasihi et al. [
10
], respectively. As a summary, an updated version of the main topics
has been reviewed here.
The RE-PtG–LNG simplified value chain is illustrated in Figure 2. The main components are:
hybrid PV–Wind power plants, electrolyser and methanation plants, CO
2
from direct air capture
units, liquefaction to LNG, LNG shipping, and regasification. Electrolyser and methanation plants
are coupled and will work simultaneously and with an SNG storage system; the liquefaction plant
can run as base load. To have a sustainable energy system with carbon neutral products, atmospheric
CO
2
is used, which is independent of the location. The output heat of the electrolysis and methanation
is used to fulfill the heat demand of the CO
2
capture plant, which increases the overall efficiency of
the system. The water demand is supplied by seawater reverse osmosis (SWRO) desalination and the
recycled water from the methanation process. As a case study, Finland has been chosen as the long
distance market for SNG, where the LNG value chain (liquefaction, shipping and regasification) cost
has been applied.
Sustainability 2017,9, 306 3 of 24
Sustainability 2017, 9, 306 3 of 24
Figure 2. The hybrid PV–Wind–PtG–LNG value chain.
Figure 3 delineates the RE-PtL value chain. The main components are: hybrid PV–Wind power
plants, electrolyser and reverse water-gas shift (RWGS) plants, CO
2
from direct air capture units,
Fischer–Tropsch (FT) plant, product upgrading unit and fuel shipping. Hydrogen and CO
2
storage
systems will guarantee the feedstock for operation of the RWGS plant and subsequently the Fischer–
Tropsch plant as base load. The light fuel gases (LFG) (C
1
–C
4
) account for 5% (mass) of FT plant
output [11]. The LFG and SNG produced in a methanation plant can be combusted to generate
electricity via a combined cycle gas turbine (CCGT) as a backup system for the constant electricity
demand of the RWGS unit. The integrated system introduces some potentials for the utilization of
waste energy, which will increase the overall efficiency and will decrease the costs. Aiming for the
maximum middle distillates share, the numbers provided by FVV [12] have been used for the model
of this paper, and represent naphtha, jet fuel and diesel with a share of 15%, 25% and 60%,
respectively.
Figure 3. The hybrid PV–Wind–PtL value chain.
Figure 2. The hybrid PV–Wind–PtG–LNG value chain.
Figure 3delineates the RE-PtL value chain. The main components are: hybrid PV–Wind
power plants, electrolyser and reverse water-gas shift (RWGS) plants, CO
2
from direct air capture
units, Fischer–Tropsch (FT) plant, product upgrading unit and fuel shipping. Hydrogen and CO
2
storage systems will guarantee the feedstock for operation of the RWGS plant and subsequently the
Fischer–Tropsch plant as base load. The light fuel gases (LFG) (C
1
–C
4
) account for 5% (mass) of FT
plant output [
11
]. The LFG and SNG produced in a methanation plant can be combusted to generate
electricity via a combined cycle gas turbine (CCGT) as a backup system for the constant electricity
demand of the RWGS unit. The integrated system introduces some potentials for the utilization of
waste energy, which will increase the overall efficiency and will decrease the costs. Aiming for the
maximum middle distillates share, the numbers provided by FVV [
12
] have been used for the model
of this paper, and represent naphtha, jet fuel and diesel with a share of 15%, 25% and 60%, respectively.
Sustainability 2017, 9, 306 3 of 24
Figure 2. The hybrid PV–Wind–PtG–LNG value chain.
Figure 3 delineates the RE-PtL value chain. The main components are: hybrid PV–Wind power
plants, electrolyser and reverse water-gas shift (RWGS) plants, CO
2
from direct air capture units,
Fischer–Tropsch (FT) plant, product upgrading unit and fuel shipping. Hydrogen and CO
2
storage
systems will guarantee the feedstock for operation of the RWGS plant and subsequently the Fischer–
Tropsch plant as base load. The light fuel gases (LFG) (C
1
–C
4
) account for 5% (mass) of FT plant
output [11]. The LFG and SNG produced in a methanation plant can be combusted to generate
electricity via a combined cycle gas turbine (CCGT) as a backup system for the constant electricity
demand of the RWGS unit. The integrated system introduces some potentials for the utilization of
waste energy, which will increase the overall efficiency and will decrease the costs. Aiming for the
maximum middle distillates share, the numbers provided by FVV [12] have been used for the model
of this paper, and represent naphtha, jet fuel and diesel with a share of 15%, 25% and 60%,
respectively.
Figure 3. The hybrid PV–Wind–PtL value chain.
Figure 3. The hybrid PV–Wind–PtL value chain.
Sustainability 2017,9, 306 4 of 24
Table 1. Synthetic fuels sector key specification.
Device Unit 2030/2040 References
Alkaline Electrolyser [13,14]
Capex /kWel 328/268
Opexfix % of capex p.a. 4
Opexvar /kWh 0.0012
Lifetime years 30
EtH2eff. (HHV) % 84
Electricity-to-heat % of inlet E 8
Methanation [14]
Capex /kWSNG 278/226
Opex % of capex p.a. 4
Lifetime years 30
Efficiency (HHV) % 77.8
Hydrogen Storage
Capex /kWhH2 0.015 [15]
A Hypothetical H2tL (RWGS, FT and Hydrocracking) Plant [10,11]
Capex k/bpd 60/54
Opex % of capex p.a. 3
Lifetime years 30
RWGS carbon conversion % 97.5
FT carbon conversion % 95
FT C5+ selectivity % 95
hydrocracking eff. % 98
Diesel Shipping
Ship size tonne (deadweight) 100,000 [16]
Capex m/ship 48 [17]
Opex % of capex p.a. 3 [16]
Lifetime years 25 [18]
Speed knots 14 [19]
Table 2. LNG value chain specification.
Device Unit 2030/2040 Reference
Liquefaction Plant
Capex k/mcm/a SNG 196 [9]
Opex % of capex p.a. 3.5 [20]
Lifetime years 25 [21]
Efficiency % 92 [9]
LNG Shipping
Ship size m3LNG 138,000 [22]
Capex m/ship 151 [20]
Opex % of capex p.a. 3.5 [20]
Lifetime years 25 [23]
Boil-off gas %/day 0.1 [24]
Speed knots 20 [19]
Maghreb—Finland sea distance km 5000 [25]
Regasification Plant
Capex k/mcm/a SNG 74 [20]
Opex % of capex p.a. 3.5 [20]
Lifetime years 30 [26]
Efficiency % 98.5 [19]
Sustainability 2017,9, 306 5 of 24
The key specification of the PtG and PtL, LNG value chain, and the feedstock (CO
2
and
water) plants are shown in Tables 13, respectively. The currency exchange rate is the long-term
average
1.35 USD/,
and the currency year for all the financial numbers and generated results is
2015. Abbreviations: capital expenditures, Capex, fixed operational expenditures, Opex
fix
, variable
operational expenditures, Opex
var
, electricity, el, higher heating value, HHV, efficiency, eff., hydrogen,
H
2
, tonne, t, barrel per day, bpd, thousand euros, k
, per annum, p.a., million, m, million cubic
meter, mcm.
Table 3. Feedstock (CO2and water) key specification.
Device Unit 2030/2040 References
CO2Direct Air Capture Plant
Capex /(tCO2·a) 228/184 [13,27]
Opex % of capex p.a. 4
Lifetime years 30
Electricity demand kWhel/tCO2 225/210 [28]
Heat demand kWhth/tCO2 1500/1350 [28]
SWRO Desalination [29,30]
Capex /(m3·day) 814/618
Opex % of capex p.a. 4
Lifetime years 30
Electricity consumption kWh/m33.15/2.85
Water extraction eff. % 45
The hybrid PV–Wind power plants, as the power source for all these technologies, should be
located in regions of very high full load hours (FLh) to reduce the levelized cost of electricity (LCOE) of
power production and subsequently the levelized cost of fuels (LCOF). Figure 4shows the cumulative
FLh for a hybrid PV–Wind power plant in the Maghreb region, where the best sites are indicated by a
red color coding [
31
,
32
]. With about 7000 FLh, Western Sahara shows the highest potential of solar
and wind in the region. In addition, the close distance to the coast, where the PtX plants could be
located, makes the power transmission cost and, consequently, the power generation cost in total as
low as possible.
Sustainability 2017, 9, 306 5 of 24
The key specification of the PtG and PtL, LNG value chain, and the feedstock (CO
2
and water)
plants are shown in Tables 1–3, respectively. The currency exchange rate is the long-term average
1.35 USD/€, and the currency year for all the financial numbers and generated results is 2015.
Abbreviations: capital expenditures, Capex, fixed operational expenditures, Opex
fix
, variable
operational expenditures, Opex
var
, electricity, el, higher heating value, HHV, efficiency, eff.,
hydrogen, H
2
, tonne, t, barrel per day, bpd, thousand euros, k€, per annum, p.a., million, m, million
cubic meter, mcm.
Table 3. Feedstock (CO
2
and water) key specification.
Device Unit 2030
2040 References
CO
2
Direct Air Capture Plant
Capex €/(t
CO2
a) 228/184 [13,27]
Opex % of capex p.a. 4
Lifetime years 30
Electricity demand kWh
el
/t
CO2
225/210 [28]
Heat demand kWh
th
/t
CO2
1500/1350 [28]
SWRO Desalination [29,30]
Capex €/(m
3
day) 814/618
Opex % of capex p.a. 4
Lifetime years 30
Electricity consumption kWh/m
3
3.15/2.85
Water extraction eff. % 45
The hybrid PV–Wind power plants, as the power source for all these technologies, should be
located in regions of very high full load hours (FLh) to reduce the levelized cost of electricity (LCOE)
of power production and subsequently the levelized cost of fuels (LCOF). Figure 4 shows the
cumulative FLh for a hybrid PV–Wind power plant in the Maghreb region, where the best sites are
indicated by a red color coding [31,32]. With about 7000 FLh, Western Sahara shows the highest
potential of solar and wind in the region. In addition, the close distance to the coast, where the PtX
plants could be located, makes the power transmission cost and, consequently, the power generation
cost in total as low as possible.
Figure 4. Maghreb’s hybrid PV–Wind power plant cumulative FLh map.
Figure 4. Maghreb’s hybrid PV–Wind power plant cumulative FLh map.
Sustainability 2017,9, 306 6 of 24
The Hourly Basis Model uses the optimized combination of PV (fixed tilted or single-axis tracking),
wind power, storage options (battery, gas storage), transmission line and PtX facilities capacity to
minimize the levelized cost of RE-SNG or RE-diesel. This is based on an hourly availability of the
solar and wind resources in a 0.45
×
0.45
spatial resolution. The datasets for solar irradiation
components and wind speed are taken from NASA databases [
32
,
33
] and partly reprocessed by the
German Aerospace Center [
34
]. Feed-in time series for fixed, optimally tilted solar PV systems are
calculated based on Gerlach et al., [
35
] and Huld et al., [
36
], and for single-axis north–south oriented
continuous horizontal tracking it is calculated based on Duffie and Beckmann [
37
]. Feed-in time series
of wind power plants are calculated for standard 3 MW wind turbines (E-101 [
38
]) with hub height
conditions of 150 m, according to Gerlach et al., [
35
]. The power sector specification for the years 2030
and 2040 are shown in Table 4.
Table 4. Power sector key specification.
Device Unit 2030/2040 References
PV Fixed Tilted
Capex /kWp480/370 [27,39,40]
Opex % of capex p.a. 1.5 [27]
Lifetime years 35/40 [41,42]
PV Single-Axis Tracking
Capex /kWp530/410 [27,39,40]
Opex % of capex p.a. 1.5 [27]
Lifetime years 35/40 [41,42]
Wind Energy (Onshore) [27]
Capex /kW 1000/940
Opex % of capex p.a. 2
Lifetime years 25
Battery (Lithium-Ion) [43]
Capex /kWhel 150/100
Opexfix /(kWh·a) 3.75/2.5
Opexvar /kWh 0.0002
Calendar life 1years 20
Full cycle life 1cycles 10000
Cycle efficiency % 93/95
Transmission Line [44]
Capex /kW/km 0.612
Opex /(kW·km·a) 0.0075
Lifetime years 50
Efficiency %/1000 km 98.4
Converter Pair Stations [44]
Capex /kW 180
Opex /(kW) 1.8
Lifetime years 50
Efficiency %/station pair 98.6
Combined Cycle Gas Turbine
Capex /kW 775 [45]
Opex % of capex p.a. 2.5 [45]
Lifetime years 35 [45]
Efficiency (LHV) % 58/60 [46]
Efficiency (HHV) % 52/54 [46]
1It is practically checked which battery lifetime limit is achieved first.
Sustainability 2017,9, 306 7 of 24
The equations below have been used to calculate the LCOE of a hybrid PV–Wind power plant
and the subsequent value chain, which follows respective guidelines published by the NREL [
47
].
Abbreviations: capital expenditures, Capex, annual operational expenditures, Opex, full load hours per
year, FLh, fuel costs, fuel, efficiency,
η
, annuity factor, crf, weighted average cost of capital, WACC,
lifetime, N, performance ratio, PR, overlap FLh, overlap. PV
irradiation
uses the irradiation on the module
surface in units of kWh/(m
2·
a), which is applied for modules under standard test conditions (STC)
for 1 kW/m
2
. The solar PV performance ratio describes the annual performance of PV systems and is
comprised of all components between the module and the point of grid access, as well as all losses
due to system downtimes or reduced yields due to not fully clean modules. The overlap is defined
by Gerlach et al. [
35
]. A WACC of 7% is used for all the calculations in the base scenario. Due to the
current financing conditions and the level of stability in the region, the assumed WACC might seem
low. However, it may be unlikely that such a situation would continue for decades. In addition, this
is the real WACC (excluding inflation, which is typically assumed to be around 2%). For the WACC
of 7% in the base scenario, assuming an equity share of 30% and an interest rate of 4%, this would
lead to a return on equity of 14%, which is rather high. The volatility of prices in a renewable energy
dominated energy system could be much lower, since all cost are fixed for decades. Hence, the price
and respective returns can also be very stable for a long term, assuming stable political conditions.
For a WACC
of 5%, the corresponding numbers would lead to a return on equity of about 7.3%, which
is still higher than expected in most feed-in tariff laws in Europe. However, it is obvious that such a
de-risking strategy would require a respective policy framework.
LCOEi=Capexi·crf +Opexi,f i x
FLhi
+Opexi,var +fuel
ηi
(1)
crf =WACC·(1+WACC)N
(1+WACC)N1(2)
FLhPV ,el =PVirradi ation ·PR (3)
LCOEgross =WindF Lh ×WindLCOE +PVFLh ×PVLCOE
(WindF Lh +PVFLh )(4)
LCOEnet =LCOEgross
1overlap (5)
3. Results
3.1. Energy and Material Flow
Figures 5and 6show the Sankey diagrams of the entire system, depicting the energy and material
flows within the entire RE-PtG–LNG and RE-PtL value chains, respectively. The figures are the
example of a system with 1 MWh
el
specific electricity input. As can be seen in Figure 5, the electrolyser,
at 97%, is the main electricity consumer in the PtG–LNG value chain, while the excess heat out of
the electrolyser and the methanation plant is the main source of energy for the CO
2
capture plant.
Delivered SNG (HHV) to the NG pipeline in Southern Europe or regasified SNG (through LNG value
chain) to Northern Europe (Finland) would be 63.7% and 57.4% of inlet electricity, respectively.
Sustainability 2017,9, 306 8 of 24
Sustainability 2017, 9, 306 8 of 24
Figure 5. RE-PtG–LNG energy and material flow diagram.
Figure 6 illustrates the energy and mass flow for the PtL value chain. As can be seen, the alkaline
electrolyser, at 93%, is the main electricity consuming element, while the excess heat by-product of
the electrolyser and the FT plant is the main source of energy for the CO
2
capture plant. The heat
released in the FT process accounts for 18% of initial electricity and 22.5% of energy content of inlet
H
2
to the system. The electricity generated by LFG combustion is equal to 1.7% of the inlet electricity.
The overall PtL efficiency of this system would be 51.5% (HHV), while 64.9% of inlet hydrogen is
converted to liquid fuels in the H
2
tL plant.
Figure 6. RE-PtL energy and material flow diagram.
Figure 5. RE-PtG–LNG energy and material flow diagram.
Figure 6illustrates the energy and mass flow for the PtL value chain. As can be seen, the alkaline
electrolyser, at 93%, is the main electricity consuming element, while the excess heat by-product of
the electrolyser and the FT plant is the main source of energy for the CO
2
capture plant. The heat
released in the FT process accounts for 18% of initial electricity and 22.5% of energy content of inlet
H
2
to the system. The electricity generated by LFG combustion is equal to 1.7% of the inlet electricity.
The overall
PtL efficiency of this system would be 51.5% (HHV), while 64.9% of inlet hydrogen is
converted to liquid fuels in the H2tL plant.
Sustainability 2017, 9, 306 8 of 24
Figure 5. RE-PtG–LNG energy and material flow diagram.
Figure 6 illustrates the energy and mass flow for the PtL value chain. As can be seen, the alkaline
electrolyser, at 93%, is the main electricity consuming element, while the excess heat by-product of
the electrolyser and the FT plant is the main source of energy for the CO
2
capture plant. The heat
released in the FT process accounts for 18% of initial electricity and 22.5% of energy content of inlet
H
2
to the system. The electricity generated by LFG combustion is equal to 1.7% of the inlet electricity.
The overall PtL efficiency of this system would be 51.5% (HHV), while 64.9% of inlet hydrogen is
converted to liquid fuels in the H
2
tL plant.
Figure 6. RE-PtL energy and material flow diagram.
Figure 6. RE-PtL energy and material flow diagram.
Sustainability 2017,9, 306 9 of 24
3.2. Hybrid PV–Wind FLh and Levelized Cost of Electricity
FLh have a major role in the final product cost. High FLh of hybrid PV–Wind power plants
result in cost reduced downstream processes such as PtG, PtL, seawater desalination and CO
2
direct
air capture. The FLh of fixed tilted PV, single-axis tracking PV and wind are shown in Figure 7.
The single-axis
PV FLh are about 400 hours more than fixed tilted PV in most parts of the Maghreb
region. Wind FLh could be much higher, but it shows a wider range. With 4800 FLh and 4000 FLh,
Western Sahara and Central Algeria have the best wind potentials, respectively. The cumulative
FLh of PV and wind reaches 7000 FLh in these regions (Figure 4), which seems a perfect place for
power generation. However, the longer distance of Central Algeria to the coast and the corresponding
transmission line cost is a negative factor for that region.
Sustainability 2017, 9, 306 9 of 24
3.2. Hybrid PV–Wind FLh and Levelized Cost of Electricity
FLh have a major role in the final product cost. High FLh of hybrid PV–Wind power plants result
in cost reduced downstream processes such as PtG, PtL, seawater desalination and CO2 direct air
capture. The FLh of fixed tilted PV, single-axis tracking PV and wind are shown in Figure 7. The
single-axis PV FLh are about 400 hours more than fixed tilted PV in most parts of the Maghreb region.
Wind FLh could be much higher, but it shows a wider range. With 4800 FLh and 4000 FLh, Western
Sahara and Central Algeria have the best wind potentials, respectively. The cumulative FLh of PV
and wind reaches 7000 FLh in these regions (Figure 4), which seems a perfect place for power
generation. However, the longer distance of Central Algeria to the coast and the corresponding
transmission line cost is a negative factor for that region.
(a)
(b) (c)
Figure 7. Wind FLh (a); PV fixed tilted FLh (b); and PV single-axis tracking FLh (c).
Besides FLh, the LCOE has a key role in the cost of synthetic fuels. Figure 8 shows the Maghreb
region’s electricity production cost of fixed tilted and single-axis tracking PV systems and wind
energy in 2030 and 2040. The minimum production cost of single-axis tracking PV in 2030 would be
20 €/MWh, which would drop down to about 15 €/MWh in 2040, and would be cheaper than fixed
tilted PV. The minimum wind electricity generation cost with 2030 technology would be 22–25
€/MWh, but, unlike PV, it is limited to Western Sahara and Central Algeria.
Figure 7. Wind FLh (a); PV fixed tilted FLh (b); and PV single-axis tracking FLh (c).
Besides FLh, the LCOE has a key role in the cost of synthetic fuels. Figure 8shows the Maghreb
region’s electricity production cost of fixed tilted and single-axis tracking PV systems and wind
energy in 2030 and 2040. The minimum production cost of single-axis tracking PV in 2030 would
be 20 /MWh,
which would drop down to about 15
/MWh in 2040, and would be cheaper than fixed
tilted PV. The minimum wind electricity generation cost with 2030 technology would be 22–25
/MWh,
but, unlike PV, it is limited to Western Sahara and Central Algeria.
Sustainability 2017,9, 306 10 of 24
Sustainability 2017, 9, 306 10 of 24
(a)
(b)
(c)
(d)
(e)
(f)
Figure 8. LCOE of fixed tilted PV in 2030 (a) and 2040 (b); single-axis tracking PV in 2030 (c) and 2040
(d); and wind in 2030 (e) and 2040 (f).
A different configuration of PtG and PtL plant results in a slightly different optimal combination
of PV and Wind. Figure 9 shows the share of installed capacity of single-axis tracking PV in the
optimal hybrid PV–Wind power plant configuration and the corresponding hybrid system LCOE for
the PtL system in 2030 and 2040. Due to lower FLh and higher LCOE, fixed tilted PV is not installed
in the model. The figure indicates that PV would be the dominating installed technology in the cost
optimal system in 2030 for most regions, except Western Sahara. Due to continued decrease in PV
Capex, a higher share of PV is installed for the year 2040. The minimum hybrid PV–Wind LCOE
would be about 20 €/MWh and 15 €/MWh in 2030 and 2040, respectively. However, the minimum
cost of delivered electricity to the PtL system on the coast would be about 30 €/MWh and 25 €/MWh
in 2030 and 2040, respectively.
Figure 8.
LCOE of fixed tilted PV in 2030 (
a
) and 2040 (
b
); single-axis tracking PV in 2030 (
c
) and 2040
(d); and wind in 2030 (e) and 2040 (f).
A different configuration of PtG and PtL plant results in a slightly different optimal combination
of PV and Wind. Figure 9shows the share of installed capacity of single-axis tracking PV in the optimal
hybrid PV–Wind power plant configuration and the corresponding hybrid system LCOE for the PtL
system in 2030 and 2040. Due to lower FLh and higher LCOE, fixed tilted PV is not installed in the
model. The figure indicates that PV would be the dominating installed technology in the cost optimal
system in 2030 for most regions, except Western Sahara. Due to continued decrease in PV Capex,
a higher
share of PV is installed for the year 2040. The minimum hybrid PV–Wind LCOE would be
about 20
/MWh and 15
/MWh in 2030 and 2040, respectively. However, the minimum cost of
delivered electricity to the PtL system on the coast would be about 30
/MWh and 25
/MWh in 2030
and 2040, respectively.
Sustainability 2017,9, 306 11 of 24
Sustainability 2017, 9, 306 11 of 24
(a)
(b)
(c)
(d)
(e)
(f)
Figure 9. Ratio of PV to hybrid PV–Wind plant installed capacity in 2030 (a) and 2040 (b); hybrid PV–
Wind LCOE in 2030 (b) and 2040 (d); and levelized cost of delivered electricity in 2030 (e) and 2040
(f); for the PtL system.
Figure 10 shows that battery capacity, transmission line cost and excess electricity (overlap and
curtailment) affect the amount and price of delivered electricity to the coast. Batteries can store a part
of the excess electricity to balance the electricity flow as well as minimize the size and cost of
electricity transmission lines and downstream PtX facilities. Modern stationary Li-ion batteries can
be operated for 10,000 cycles, but batteries used in the model show up to 330 full charge cycles per
year. This would be equivalent to 30 years, which is more than the calendar life assumption in this
paper (20 years). The share of battery storage increases significantly from 2030 to 2040 and reaches
up to 45% of the hybrid PV–Wind power installed capacity in the south of Algeria, with high distance
to the sea (approximately 2000 km). The transmission line cost in most regions with a distance of up
Figure 9.
Ratio of PV to hybrid PV–Wind plant installed capacity in 2030 (
a
) and 2040 (
b
); hybrid
PV–Wind LCOE in 2030 (
c
) and 2040 (
d
); and levelized cost of delivered electricity in 2030 (
e
) and 2040
(f); for the PtL system.
Figure 10 shows that battery capacity, transmission line cost and excess electricity (overlap and
curtailment) affect the amount and price of delivered electricity to the coast. Batteries can store a
part of the excess electricity to balance the electricity flow as well as minimize the size and cost of
electricity transmission lines and downstream PtX facilities. Modern stationary Li-ion batteries can
be operated for 10,000 cycles, but batteries used in the model show up to 330 full charge cycles per
year.
This would
be equivalent to 30 years, which is more than the calendar life assumption in this
paper (20 years). The share of battery storage increases significantly from 2030 to 2040 and reaches up
to 45% of the hybrid PV–Wind power installed capacity in the south of Algeria, with high distance to
the sea (approximately 2000 km). The transmission line cost in most regions with a distance of up to
Sustainability 2017,9, 306 12 of 24
1000 km would not exceed 10–12
/MWh
el
. For an optimal system, the percentage of excess electricity
for PtL systems would be up to 15% for regions far from the coast and with a high share of wind. This
would happen in a wider region in 2040, as the lower cost of electricity production makes electricity
curtailment a cheaper option to balance the system.
Sustainability 2017, 9, 306 12 of 24
to 1000 km would not exceed 10–12 €/MWh
el
. For an optimal system, the percentage of excess
electricity for PtL systems would be up to 15% for regions far from the coast and with a high share of
wind. This would happen in a wider region in 2040, as the lower cost of electricity production makes
electricity curtailment a cheaper option to balance the system.
(a)
(b)
(c)
(d)
(e)
(f)
Figure 10. Ratio of battery to hybrid PV–Wind power plant installed capacity in 2030 (a) and 2040 (b);
LCOE transmission in 2030 (e) and 2040 (d); excess electricity in percentage of generation in 2030 (e)
and 2040 (f); for the PtL system.
3.3. Levelized Cost and Production Potential of Synthetic Fuels
The price and FLh of delivered electricity to the PtX plants will result in SNG, regasified SNG
(in Finland) and synthetic liquid fuels (SLF) costs, illustrated in Figure 11. In 2030, the cheapest SNG
could be generated in Western Sahara, along the coast, while the area for the cheapest SNG expands
Figure 10.
Ratio of battery to hybrid PV–Wind power plant installed capacity in 2030 (
a
) and 2040 (
b
);
LCOE transmission in 2030 (
c
) and 2040 (
d
); excess electricity in percentage of generation in 2030 (
e
)
and 2040 (f); for the PtL system.
3.3. Levelized Cost and Production Potential of Synthetic Fuels
The price and FLh of delivered electricity to the PtX plants will result in SNG, regasified SNG
(in Finland) and synthetic liquid fuels (SLF) costs, illustrated in Figure 11. In 2030, the cheapest SNG
could be generated in Western Sahara, along the coast, while the area for the cheapest SNG expands to
Sustainability 2017,9, 306 13 of 24
Morocco, Libya and some parts of Mauritania in 2040. The cost difference between SNG and regasified
SNG stands for the LNG value chain. This will make regasified SNG as expensive as SLF in 2030, while
in 2040 regasified SNG would be cheaper in most regions and SLF shows a wider cost range.
Sustainability 2017, 9, 306 13 of 24
to Morocco, Libya and some parts of Mauritania in 2040. The cost difference between SNG and
regasified SNG stands for the LNG value chain. This will make regasified SNG as expensive as SLF
in 2030, while in 2040 regasified SNG would be cheaper in most regions and SLF shows a wider
(a)
(b)
(c)
(d)
(e)
(f)
Figure 11. Cost of SNG in 2030 (a) and 2040 (b); cost of regasified SNG in Finland in 2030 (e) and 2040
(d); and cost of synthetic liquid fuels in 2030 (e) and 2040 (f).
A summary of the electricity and synthetic fuel generation costs at the least cost node, located in
Western Sahara, has been illustrated in Figure 12. The electricity generation cost at this node is not
the cheapest one, but due to a higher share of wind and, consequently FLh, this leads to the cheapest
synthetic fuel generation cost. With a minimum production cost of 88 €/MWh
th,HHV
(0.85 €/L), RE-
diesel production cost is about 16% higher than SNG, but it would be cheaper than regasified SNG.
For a SNG production cost of 80 €/MWh
th,HHV
(0.66 €/m
3SNG
), the LNG value chain would cost 13
€/MWh
th,HHV
, while this increases to 15 €/MWh
th,HHV
for a SNG price of 100 €/MWh
th,HHV
(1.03 €/m
3SNG
),
Figure 11.
Cost of SNG in 2030 (
a
) and 2040 (
b
); cost of regasified SNG in Finland in 2030 (
c
) and 2040
(d); and cost of synthetic liquid fuels in 2030 (e) and 2040 (f).
A summary of the electricity and synthetic fuel generation costs at the least cost node, located in
Western Sahara, has been illustrated in Figure 12. The electricity generation cost at this node is not
the cheapest one, but due to a higher share of wind and, consequently FLh, this leads to the cheapest
synthetic fuel generation cost. With a minimum production cost of 88
/MWh
th,HHV (0.85 /L),
RE-diesel production cost is about 16% higher than SNG, but it would be cheaper than regasified
SNG. For a SNG production cost of 80
/MWh
th,HHV
(0.66
/m
3SNG
), the LNG value chain would
Sustainability 2017,9, 306 14 of 24
cost
13 /MWhth,HHV,
while this increases to 15
/MWh
th,HHV
for a SNG price of 100
/MWh
th,HHV
(1.03 /m3SNG),
due to the higher cost of efficiency losses. The SNG and SLF production costs decrease
by about 13% and 5%, respectively, from 2030 to 2040. The sharper decrease in SNG production cost is
due to a sharper decrease in the Capex projected for the PtG system and a sharper increase in the FLh
of the PtG system.
Sustainability 2017, 9, 306 14 of 24
due to the higher cost of efficiency losses. The SNG and SLF production costs decrease by about 13%
and 5%, respectively, from 2030 to 2040. The sharper decrease in SNG production cost is due to a
sharper decrease in the Capex projected for the PtG system and a sharper increase in the FLh of the
PtG system.
Figure 12. RE and synthetic fuels production cost (based on HHV) at the least cost node for the base
scenario in 2030 and 2040.
The optimal sample case can be scaled up to generate more electricity and, consequently,
synthetic fuels. A maximum 10% of land is allowed for PV and wind installation. The data for the
optimal installed capacity and generation potential of hybrid PV–Wind, PtG and PtL plants in 2030
and 2040 is shown in Table 5 and has been visualized in Figure 13. Algeria and Libya comprise 73%
of total installed capacity and generation potential of all technologies and fuels in the Maghreb region.
In addition to the size of the country, hybrid PV–Wind installed capacity is a factor of the ratio of
installed technologies, as the installed capacity potential of PV is 8.9 times bigger than a wind power
plant in the same area. This is the reason for lower hybrid PV–Wind installed capacity for PtG than
PtL in the same country and the same year. An optimized PtG system needs to operate on higher FLh
than a PtL system, thus more wind power capacity would be installed which reaches its area limit at
a lower installed capacity. From 2030 to 2040, there would be an increase in the total installed capacity
of hybrid PV–Wind power plants, which is due to an increase in the share of PV (Figure 9).
In 2030, even with higher hybrid PV–Wind installed capacities, the optimal installed capacity
potential of PtL is only 48% of the total optimal PtG installation potential. In addition to lower
efficiency, this is because, with the aid of hydrogen storage, the downstream part of the PtL system
(RWGS and FT) would be operated as base load, while in the PtG system it is directly connected to
the source of power. Thus, the operating time of the system is lower, but at a higher level of capacities.
Even with constant PtX efficiency through 2030 to 2040, the generation potential increases from 2030
to 2040, due to the higher share of single-axis tracking PV in 2040, which has a higher generation
potential than wind in the same area. Figure 14 presents the optimal annual PtG and PtL production
volume (Figure 13) sorted in order of the specific generation cost, in 2030 and 2040. The production
cost increases about 20 €/MWhth,fuel for the first 1000 TWhth. To boost the volume of cheap fuel
production, desirable nodes can be completely covered by solar PV plants or wind farms if their site
is outside of an inhabited region.
The industrial cost curves for the Maghreb region have been broken down by country in Figure
15, which makes it possible to investigate the production potential of each country under any cost
level, in 2030 and 2040.
Figure 12.
RE and synthetic fuels production cost (based on HHV) at the least cost node for the base
scenario in 2030 and 2040.
The optimal sample case can be scaled up to generate more electricity and, consequently, synthetic
fuels. A maximum 10% of land is allowed for PV and wind installation. The data for the optimal
installed capacity and generation potential of hybrid PV–Wind, PtG and PtL plants in 2030 and 2040
is shown in Table 5and has been visualized in Figure 13. Algeria and Libya comprise 73% of total
installed capacity and generation potential of all technologies and fuels in the Maghreb region. In
addition to the size of the country, hybrid PV–Wind installed capacity is a factor of the ratio of installed
technologies, as the installed capacity potential of PV is 8.9 times bigger than a wind power plant
in the same area. This is the reason for lower hybrid PV–Wind installed capacity for PtG than PtL
in the same country and the same year. An optimized PtG system needs to operate on higher FLh
than a PtL system, thus more wind power capacity would be installed which reaches its area limit at a
lower installed capacity. From 2030 to 2040, there would be an increase in the total installed capacity of
hybrid PV–Wind power plants, which is due to an increase in the share of PV (Figure 9).
In 2030, even with higher hybrid PV–Wind installed capacities, the optimal installed capacity
potential of PtL is only 48% of the total optimal PtG installation potential. In addition to lower
efficiency, this is because, with the aid of hydrogen storage, the downstream part of the PtL system
(RWGS and FT) would be operated as base load, while in the PtG system it is directly connected to the
source of power. Thus, the operating time of the system is lower, but at a higher level of capacities.
Even with constant PtX efficiency through 2030 to 2040, the generation potential increases from 2030
to 2040, due to the higher share of single-axis tracking PV in 2040, which has a higher generation
potential than wind in the same area. Figure 14 presents the optimal annual PtG and PtL production
volume (Figure 13) sorted in order of the specific generation cost, in 2030 and 2040. The production cost
increases about 20
/MWh
th,fuel
for the first 1000 TWh
th
. To boost the volume of cheap fuel production,
desirable nodes can be completely covered by solar PV plants or wind farms if their site is outside of
an inhabited region.
The industrial cost curves for the Maghreb region have been broken down by country in Figure 15,
which makes it possible to investigate the production potential of each country under any cost level, in
2030 and 2040.
Sustainability 2017,9, 306 15 of 24
Table 5. Optimal installed capacity and production potential of hybrid PV–Wind, PtG and PtL plants.
Unit
2030 2040
PtG PtL PtG PtL
Hybrid PV–Wind SNG Hybrid PV–Wind SLF Hybrid PV–Wind SNG Hybrid PV–Wind SLF
Capacity
Algeria GW 10,030 3055 12,499 1427 14,273 3684 15,051 1614
Libya GW 5732 1814 7593 922 8699 2619 10,200 1154
Mauritania GW 2204 573 3039 365 3858 984 4514 500
Morocco GW 2680 971 2772 332 2841 1004 2918 328
Tunisia GW 649 196 862 89 991 312 1069 102
Western Sahara GW 433 119 460 69 534 149 863 111
Total GW 21,728 6728 27,225 3204 31,196 8752 34,615 3809
Production
Algeria TWh 22,413 12,256 27,798 12,498 31,643 17,082 33,313 14,136
Libya TWh 13,350 7509 17,454 8074 19,957 11,078 23,199 10,106
Mauritania TWh 5183 2902 6931 3202 8611 4862 9956 4376
Morocco TWh 6016 3405 6209 2906 6344 3540 6490 2869
Tunisia TWh 1256 705 1671 776 1906 1040 2057 892
Western Sahara TWh 1234 694 1295 601 1455 814 2182 975
Total TWh 49,452 27,471 61,358 28,057 69,916 38,416 77,197 33,354
Sustainability 2017,9, 306 16 of 24
Sustainability 2017, 9, 306 16 of 24
(a)
(b)
Figure 13. Optimal installed capacity (a) and production (b) potential of hybrid PV–Wind, PtG and
PtL plants.
Figure 14. PtG (SNG) and PtL (SLF) industrial cost curves for cost optimized production based on
hybrid PV–Wind power in a cumulative distribution, in 2030 and 2040.
Figure 13.
Optimal installed capacity (
a
) and production (
b
) potential of hybrid PV–Wind, PtG and
PtL plants.
Sustainability 2017, 9, 306 16 of 24
(a)
(b)
Figure 13. Optimal installed capacity (a) and production (b) potential of hybrid PV–Wind, PtG and
PtL plants.
Figure 14. PtG (SNG) and PtL (SLF) industrial cost curves for cost optimized production based on
hybrid PV–Wind power in a cumulative distribution, in 2030 and 2040.
Figure 14.
PtG (SNG) and PtL (SLF) industrial cost curves for cost optimized production based on
hybrid PV–Wind power in a cumulative distribution, in 2030 and 2040.
Sustainability 2017,9, 306 17 of 24
Sustainability 2017, 9, 306 17 of 24
(a)
(b)
Figure 15. PtG (SNG) and PtL (SLF) industrial cost curves for cost optimized production based on
hybrid PV–Wind power in a cumulative distribution for each country in the Maghreb region; in 2030
(a) and 2040 (b).
3.4. Business Case and Cost Drivers for Reaching Fuel-Parity
As discussed in the introduction, by 2030 there would be countries that may only demand carbon
neutral hydrocarbons, i.e., fossil-based fuels would not be accepted anymore in those countries.
However, in general the RE-SNG and RE-diesel should compete with NG, LNG and conventional
diesel in the market, which is a function of the crude oil price and in the case of diesel, also a function
of refining cost. The 32-year average ratio of NG price in Germany (as a European country) to crude
oil price is 77.9% [9,48]. In addition, for the latest six-year average, the NG price in Germany has been
at the same level as the Spanish LNG price [49,50]. The 13-year average ratio of one barrel of diesel
cost to crude oil price is 118.8% [10,51]. With current crude oil prices and the projected costs of
synthetic fuels in 2030 and 2040 for the base scenario, synthetic fuels would not become comparable.
However, an increase in crude oil price or CO
2
emission cost will increase the cost of NG and
conventional diesel, while a profitable business case for O
2
or a feasible business case at a de-risked
5% WACC level can lead to lower cost for RE-synthetic fuels. In this study, according to Bloomberg
New Energy Outlook 2015 [52], the additional cost of CO
2
emissions on conventional hydrocarbons
with a maximum price of 61 €/t
CO2
in 2030 and 75 €/t
CO2
in 2040 has been taken into account. The
market price of oxygen for industrial purposes can be up to 80 €/t
O2
[8]. Nevertheless, the projection
of a maximum 20 €/t
O2
benefit from oxygen utilization is assumed in this study, while there is no
Figure 15.
PtG (SNG) and PtL (SLF) industrial cost curves for cost optimized production based on
hybrid PV–Wind power in a cumulative distribution for each country in the Maghreb region; in 2030
(a) and 2040 (b).
3.4. Business Case and Cost Drivers for Reaching Fuel-Parity
As discussed in the introduction, by 2030 there would be countries that may only demand
carbon neutral hydrocarbons, i.e., fossil-based fuels would not be accepted anymore in those countries.
However, in general the RE-SNG and RE-diesel should compete with NG, LNG and conventional
diesel in the market, which is a function of the crude oil price and in the case of diesel, also a function
of refining cost. The 32-year average ratio of NG price in Germany (as a European country) to crude oil
price is 77.9% [
9
,
48
]. In addition, for the latest six-year average, the NG price in Germany has been at
the same level as the Spanish LNG price [
49
,
50
]. The 13-year average ratio of one barrel of diesel cost
to crude oil price is 118.8% [
10
,
51
]. With current crude oil prices and the projected costs of synthetic
fuels in 2030 and 2040 for the base scenario, synthetic fuels would not become comparable. However,
an increase in crude oil price or CO
2
emission cost will increase the cost of NG and conventional diesel,
while a profitable business case for O
2
or a feasible business case at a de-risked 5% WACC level can
lead to lower cost for RE-synthetic fuels. In this study, according to Bloomberg New Energy Outlook
2015 [
52
], the additional cost of CO
2
emissions on conventional hydrocarbons with a maximum price
of 61
/t
CO2
in 2030 and 75
/t
CO2
in 2040 has been taken into account. The market price of oxygen
Sustainability 2017,9, 306 18 of 24
for industrial purposes can be up to 80
/t
O2
[
8
]. Nevertheless, the projection of a maximum 20
/t
O2
benefit from oxygen utilization is assumed in this study, while there is no benefit from oxygen
utilization in the base scenario. The effects of all these factors have been summarized in Figure 16.
The prices of NG and diesel in the EU are based on:
the global crude oil price for a price range of 40–200 USD/barrel;
two scenarios for CO2emission cost;
two scenarios for benefits from O2sales; and
the cost of delivered RE-SNG or RE-diesel based on two different WACC levels.
All projections are for the years 2030 and 2040.
Sustainability 2017, 9, 306 18 of 24
benefit from oxygen utilization in the base scenario. The effects of all these factors have been
summarized in Figure 16. The prices of NG and diesel in the EU are based on:
the global crude oil price for a price range of 40–200 USD/barrel;
two scenarios for CO
2
emission cost;
two scenarios for benefits from O
2
sales; and
the cost of delivered RE-SNG or RE-diesel based on two different WACC levels.
All projections are for the years 2030 and 2040.
(a)
(b)
Figure 16. Different scenarios for the RE-SNG and RE-diesel production cost in the Maghreb region
(Western Sahara) and regasified RE-SNG price in Finland, in: 2030 (a); and 2040 (b). Reading example:
For a crude oil price of 100 USD/bbl in 2040, the conventional diesel price varies from 52–73 €/MWh
th
(depending on the CO
2
emission cost), while the RE-diesel cost varies from 65–83 €/MWh
th
(depending on WACC and O
2
benefit).
At 76 €/MWh
th,HHV
(0.78 €/m
3SNG
), RE-SNG has a lower production cost in comparison to 88
€/MWh
th,HHV
(0.85 €/L) for RE-diesel, in 2030. On the other hand, the market price of diesel per unit of
energy is significantly higher than natural gas. Moreover, CO
2
emissions of diesel per unit of energy
Figure 16.
Different scenarios for the RE-SNG and RE-diesel production cost in the Maghreb region
(Western Sahara) and regasified RE-SNG price in Finland, in: 2030 (
a
); and 2040 (
b
). Reading example:
For a crude oil price of 100 USD/bbl in 2040, the conventional diesel price varies from 52–73
/MWh
th
(depending on the CO
2
emission cost), while the RE-diesel cost varies from 65–83
/MWh
th
(depending
on WACC and O2benefit).
Sustainability 2017,9, 306 19 of 24
At 76
/MWh
th,HHV
(0.78
/m
3SNG
), RE-SNG has a lower production cost in comparison to
88 /MWhth,HHV
(0.85
/L) for RE-diesel, in 2030. On the other hand, the market price of diesel
per unit of energy is significantly higher than natural gas. Moreover, CO
2
emissions of diesel per
unit of energy are more than NG, thus CO
2
emission cost would have a greater impact on the price
of conventional diesel. Thus, in total, RE-diesel can reach market parity at lower crude oil prices.
This market parity can also be called fuel-parity, since for the applied assumptions the fossil and
RE-based fuels result in the same cost in the target markets. The fuel-parity concept and its impacts
are further explained by Breyer et al. [
53
]. The first breakeven point, in 2030, can be expected for
produced RE-diesel with a WACC of 5%, CO
2
emission cost of 61
/t
CO2
, accessible oxygen price of
20 /tO2
and a crude oil price of about 101 USD/bbl, in 2030. While RE-diesel produced under the
base case (WACC of 7%, no CO
2
emission cost and no O
2
sales) can reach fuel-parity with conventional
diesel whenever the crude oil price is higher than about 169 USD/bbl. In 2040, this range decreases
to
86–160 USD/bbl.
In the case of RE-SNG the first breakeven point can be expected for a crude oil
price of 142 and
107 USD/bbl
in 2030 and 2040, respectively. The regasified RE-SNG would reach
fuel-parity at about 30 USD/bbl higher crude oil prices. These represent a very high difference and the
base case may not easily match with market prices. However, the additional assumptions are not far
from reality, since a CO2emission cost is already applied in some countries [54].
4. Discussion and Conclusions
Synthetic fuel production for Europe based on hybrid PV–Wind power plants in the Maghreb
region is technically feasible by the year 2030. In general, the system can run if the final product is cost
competitive or there is a ban on fossil fuels. This study shows that, for the base scenario, RE-diesel
produced in the Maghreb region in 2030 can reach fuel-parity with RE-diesel in the EU for a crude oil
price of 169 USD/bbl, while RE-SNG in Southern Europe and regasified RE-SNG in Finland would
not reach fuel-parity for the studied crude oil price of up to 200 USD/bbl. These are more than the
prices of conventional fossil diesel or NG in today’s markets. However, application of CO
2
emission
cost, a profitable business case for O
2
, a feasible business case at a de-risked 5% WACC level, further
advances in technologies, or cost reductions by 2040 can decrease the fuel-parity for RE-diesel and
RE-SNG to crude oil prices of 86 and 107 USD/bbl, respectively. For this matter, a study of oxygen
demand in the Maghreb region and Southern Europe is essential. In addition, the improvement of
stability in the region will encourage investors to choose the Maghreb region for their investment in
this sector. However, the Opex for solar PV might be higher in some parts of the Maghreb region with
very harsh climate. The WACC may vary between 5% and 9% around the assumed 7%, depending on
economic and political constraints. To reflect the impact of these factors, sensitivity analyses have been
performed for WACC and the solar PV Opex for PtG in 2030, as an example. As illustrated in Figure 17,
a WACC of 9% would increase the SNG production cost by about 17%. However, the corresponding
return on equity would be around 18% (for 5% interest rate and 70% debt financing), a level that
reflects either extreme high risk or a business case which is close to being greedy.
The solar
PV Opex
sensitivity analysis shows that a 0.1% absolute increase of annual Opex as a percentage of Capex
leads to 1.08% higher PV LCOE and 0.4% higher synthetic fuels cost. The lower impact on fuel final
production cost is because the optimized combination of different technologies would be rebalanced
in order to minimize the cost effect of PV LCOE. For example, more wind power or batteries would be
installed in the newly optimized system. Moreover, the Opex increase effect is almost negligible for
production up to 300 TWh
th
in the least cost production sites characterized by a very low share of PV
(Figure 9a).
Sustainability 2017,9, 306 20 of 24
Sustainability 2017, 9, 306 20 of 24
Figure 17. PtG (SNG) sensitivity analysis for different WACC and solar PV Opex assumptions in 2030.
Apart from direct air capture (DAC), other carbon capture and utilization (CCU) methods such
as CO
2
from waste-to-energy plants, pulp and paper plants and the raw material from cement mills
could be used in order to give the model more flexibility to find the least cost option. The direct air
capturing CO
2
units in the current system are mainly powered by waste heat from the PtG or PtL
plants and can deliver CO
2
with a cost range of 30–80 €/tonne in an optimized PtX system. Any other
CO
2
source has to compete with this cost reference to achieve a positive effect on the overall cost-
optimized system. Aghahosseini et al. [55] concluded for the Middle East and Northern Africa
(MENA) region that the sector integration of a 100% renewable electricity system with seawater
desalination and industrial gas demand could lead to an additional cost benefit for the total energy
system of 10.8%, due to an increased level of flexibility, which may be used for a further optimization
of the utilization of intermittent RE sources. The PtX options discussed in this article have not yet
been integrated in a comprehensive energy system analysis investigating further potential cost
reductions due to more flexibility.
RE-diesel would be a more attractive case than SNG if the current energy system continued.
Nevertheless, the production cost of synthetic fuels is not the only factor when choosing one fuel as
the best option. Preference also depends on each one’s application and the corresponding demand.
However, the world’s energy system will become mainly electrified in future, thus the market size
for hydrocarbons would shrink to mainly aviation, heavy vehicles, and non-energetic industrial
purposes. Thus, the chances are high that there would always be a surplus of crude oil and NG, which
can easily keep the market price below the synthetic fuels production cost.
On the other hand, there would be more restrictions on fossil-based hydrocarbons due to
environmental issues and emissions cost, in particular due to the global net zero agreement at COP21
in Paris. The standards for fuel quality may rise to a limit at which NG and conventional diesel and
jet fuel cannot be produced at that quality anymore. In that case, carbon-neutral, sulfur-free SNG and
SLF can be considered as one of the main substitutions, even at a higher production cost. In that case,
RE-synthetic fuels produced in the Maghreb region would be one of the cheapest available options
for Europe. Thus, a decent market potential is seen for both SNG and RE-diesel for the EU in 2030
and 2040, which the Maghreb region can address and gain a significant share.
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 thanks
the Gasum Gas Fund for the valuable scholarship. We also thank Michael Child for proofreading.
Author Contributions: Dmitrii Bogdanov did the initial coding of the hourly model; Mahdi Fasihi performed
the research, developed the code, generated the results, analyzed the data, and wrote the manuscript; and
Christian Breyer framed the research questions and scope of the work and cross-checked results, assumptions
and the manuscript.
Figure 17.
PtG (SNG) sensitivity analysis for different WACC and solar PV Opex assumptions in 2030.
Apart from direct air capture (DAC), other carbon capture and utilization (CCU) methods such as
CO
2
from waste-to-energy plants, pulp and paper plants and the raw material from cement mills could
be used in order to give the model more flexibility to find the least cost option. The direct air capturing
CO
2
units in the current system are mainly powered by waste heat from the PtG or PtL plants and
can deliver CO
2
with a cost range of 30–80
/tonne in an optimized PtX system. Any other CO
2
source has to compete with this cost reference to achieve a positive effect on the overall cost-optimized
system. Aghahosseini et al. [
55
] concluded for the Middle East and Northern Africa (MENA) region
that the sector integration of a 100% renewable electricity system with seawater desalination and
industrial gas demand could lead to an additional cost benefit for the total energy system of 10.8%,
due to an increased level of flexibility, which may be used for a further optimization of the utilization
of intermittent RE sources. The PtX options discussed in this article have not yet been integrated
in a comprehensive energy system analysis investigating further potential cost reductions due to
more flexibility.
RE-diesel would be a more attractive case than SNG if the current energy system continued.
Nevertheless, the production cost of synthetic fuels is not the only factor when choosing one fuel as
the best option. Preference also depends on each one’s application and the corresponding demand.
However, the world’s energy system will become mainly electrified in future, thus the market size for
hydrocarbons would shrink to mainly aviation, heavy vehicles, and non-energetic industrial purposes.
Thus, the chances are high that there would always be a surplus of crude oil and NG, which can easily
keep the market price below the synthetic fuels production cost.
On the other hand, there would be more restrictions on fossil-based hydrocarbons due to
environmental issues and emissions cost, in particular due to the global net zero agreement at COP21
in Paris. The standards for fuel quality may rise to a limit at which NG and conventional diesel and jet
fuel cannot be produced at that quality anymore. In that case, carbon-neutral, sulfur-free SNG and
SLF can be considered as one of the main substitutions, even at a higher production cost. In that case,
RE-synthetic fuels produced in the Maghreb region would be one of the cheapest available options for
Europe. Thus, a decent market potential is seen for both SNG and RE-diesel for the EU in 2030 and
2040, which the Maghreb region can address and gain a significant share.
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 thanks
the Gasum Gas Fund for the valuable scholarship. We also thank Michael Child for proofreading.
Author Contributions:
Dmitrii Bogdanov did the initial coding of the hourly model; Mahdi Fasihi performed
the research, developed the code, generated the results, analyzed the data, and wrote the manuscript;
and Christian Breyer
framed the research questions and scope of the work and cross-checked results, assumptions
and the manuscript.
Sustainability 2017,9, 306 21 of 24
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.
Nomenclature
AEC Alkaline Electrolysis Cell
bpd Barrel per day
Capex Capital Expenditures
CCU Carbon Capture and Utilization
CCS Carbon Capture and Storage
COP Conference of the Parties
crf Capital recovery factor
Eq Equation
DAC Direct Air Capture
FLh Full Load hours
FT Fischer–Tropsch
h hour
H2tL Hydrogen-to-Liquids
HHV Higher Heating Value
HT High Temperature
LCOE Levelized Cost of Electricity
LCOF Levelized Cost of Fuel
LFG Light Fuel Gases
LHV Lower Heating Value
LNG Liquefied Natural Gas
LT Low Temperature
N Lifetime
NG Natural Gas
Opex Operational Expenditures
PR Performance Ratio
PtG Power-to-Gas
PtL Power-to-Liquids
PV Photovoltaic
RE Renewable Electricity
RO Reverse Osmosis
RWGS Reverse Water-Gas Shift
SLF Synthetic Liquid Fuels
SNG Synthetic Natural Gas
SWRO Seawater Reverse Osmosis
t Tonne
USD United States dollar
WACC Weighted Average Cost of Capital
WS Water Storage
ηEfficiency
Subscripts
el electricity
fix fixed
sf Synthetic Fuels
th thermal
var variable
Sustainability 2017,9, 306 22 of 24
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    Recent global modelling studies suggest a decline of long-distance trade in energy carriers in future global renewable energy systems, compared to today's fossil fuel based system. In contrast, we identify four drivers that facilitate trade of renewable energy carriers. These drivers may lead to trade volumes remaining at current levels or even to an increase during the transition to an energy system with very high shares of renewables. First, new land-efficient technologies for renewable fuel production become increasingly available and technically allow for long-distance trade in renewables. Second, regional differences in social acceptance and land availability for energy infrastructure support the development of renewable fuel import and export streams. Third, the economics of renewable energy systems, i.e. the different production conditions globally and the high costs of fully renewable regional electricity systems, will create opportunities for spatial arbitrage. Fourth, a reduction of stranded investments in the fossil fuel sector is possible by switching from fossil fuels to renewable fuel trade. The impact of these drivers on trade in renewable energy carriers is currently under-investigated by the global energy systems research community. The importance of the topic, in particular as trade can redistribute profits and losses of decarbonization and may hence support finding new partners in climate change mitigation negotiations, warrants further research efforts in this area therefore. Broader context Mitigating climate change requires a global transition towards energy systems with low or even negative greenhouse gas emissions. While there are multiple options to design such systems, reaching very high shares of electricity generation from renewable sources is frequently considered to be among the best available ones. Scenarios of such a global transition, summarized for example by the Intergovernmental Panel on Climate Change, indicate a decline in intercontinental trade in energy carriers as electricity generation from renewable sources increases. In other words, highly renewable energy systems are foreseen to be largely regional. This, however, is not necessarily the case. Quite contrary, intercontinental trade in renewable solar and electric fuels may become a major option in the coming decades. Our article presents four main drivers of this development related to new technologies, regional differences in social conflicts related to renewable energy infrastructure, the economics of renewable energy systems, and the possible continuation of the use of otherwise stranded fossil fuel infrastructure. The development of global renewable fuel trade streams may cause unintended social, technical, and economic consequences. We therefore call for a major research effort to increase our understanding of an energy future with high shares of renewable fuel trade.
  • Article
    Full-text available
    Pathways for achieving the 1.5–2 °C global temperature moderation target imply a massive scaling of carbon dioxide (CO2) removal technologies, in particular in the 2040s and onwards. CO2 direct air capture (DAC) is among the most promising negative emission technologies (NETs). The energy demands for low-temperature solid-sorbent DAC are mainly heat at around 100 °C and electricity, which lead to sustainably operated DAC systems based on low-cost renewable electricity and heat pumps for the heat supply. This analysis is carried out for the case of the Maghreb region, which enjoys abundantly available low-cost renewable energy resources. The energy transition results for the Maghreb region lead to a solar photovoltaic (PV)-dominated energy supply with some wind energy contribution. DAC systems will need the same energy supply structure. The research investigates the levelised cost of CO2 DAC (LCOD) in high spatial resolution and is based on full hourly modelling for the Maghreb region. The key results are LCOD of about 55 €/tCO2 in 2050 with a further cost reduction potential of up to 50%. The area demand is considered and concluded to be negligible. Major conclusions for CO2 removal as a new energy sector are drawn. Key options for a global climate change mitigation strategy are first an energy transition towards renewable energy and second NETs for achieving the targets of the Paris Agreement.
  • Article
    The Paris Agreement sets a clear target for net zero greenhouse gas (GHG) emissions by the mid‐21st century. This implies that the transport sector has to reach zero GHG emissions mainly through direct and indirect electrification in the form of synthetic fuels, such as hydrogen and Fischer‐Tropsch (FT) fuels. The results of this research document that this very ambitious target is possible. This research analyses the global solar photovoltaics (PV) demand for achieving the Paris targets in the transport sector by the year 2050. The methodology is composed of the derivation of the transportation demand converted into final energy demand for direct electrification, hydrogen, methane, and FT‐fuels production. The power‐to‐gas (H2, CH4) and power‐to‐liquids (FT fuels) value chains are applied for the total electricity demand, which will be mostly fulfilled by PV, taking into account previous results concerning the renewable electricity share of the energy transition in the power sector for the world structured in 145 regions and results aggregated to nine major regions. The results show a continuous demand increase for all transportation modes till 2050. The total global PV capacity demand by 2050 for the transport sector is estimated to be about 19.1 TWp, thereof 35%, 25%, 7%, and 33% for direct electrification, hydrogen, synthetic natural gas, and FT fuels, respectively. PV will be the key enabler of a full defossilisation of the transport sector with a demand comparable with the power sector but a slightly later growth dynamic, leading to a combined annual PV capacity demand of about 1.8 TWp around 2050.
  • Article
    High shares of renewable energy, particularly wind power, were modelled in several future scenarios for the Scottish energy system. In the first part of this work, it was determined that Scotland could produce the equivalent baseload power for supply to England at a lower overall cost (99 €/MWh) than the proposed subsidized price (112 €/MWh) to be paid for electricity generated from the proposed Hinkley Point C nuclear power plant. This cost includes all extra generation capacity and transmission lines. In the second part of this work, it was determined that a 100% renewable energy system could be achieved at an annualized cost of 10.7 b€/a, approximately 8% less than the 11.7 b€/a expected for an energy system composed of 75% renewable energy. In the 100% renewable energy system, cost savings are achieved through effective energy storage, sector integration, and flexible generation from dispatchable renewable energy resources, such as hydropower (1.7 GWe), bioenergy, and synthetic fuels. Complementary resources to 23.4 GWe of wind power also included solar photovoltaics (10.1 GWe), tidal power (1.5 GWe), and wave power (0.3 GWe). It was also determined that carbon capture and utilization would be a preferable strategy to carbon capture and storage for Scotland. Complete defossilization of the Scottish energy system appears feasible by 2050, given the assumptions used in this study.
  • Article
    Für eine aus Gesamtsystemsicht kosteneffiziente Reduktion der CO2-Intensität der Energieversorgung, muss eine sektorübergreifende Betrachtung und Priorisierung von Transformationsschritten erfolgen. Energietechnologien, in denen konventionelle oder erneuerbare Gase anstelle von Öl oder Kohle eingesetzt werden, stellen dabei potenzielle Maßnahmen zur Reduktion von CO2-Emissionen dar. In dieser Studie wurden resultierende Mehr- bzw. Minderkosten durch die Neuinvestition in gasbasierte anstelle von kohle- und erdölbasierten Technologien ermittelt. Die Untersuchungen wurden sowohl für aktuelle als auch für das Jahr 2030 erwartete Kostenstrukturen der Energieträger und Technologien durchgeführt. Zudem wurde zwischen resultierenden Kosten aus Akteurs- und Systemsicht unterschieden. Die Ergebnisse verdeutlichen, dass speziell im Bereich der Hochtemperatur-Prozesswärme und des Individualverkehrs sehr hohe CO2-Verminderungskosten vorliegen. Der Bereich der Niedertemperaturbereitstellung weist hingegen geringe CO2-Verminderungskosten auf, teilweise ist hier sogar mit einer Kostenersparnis durch den Einsatz gasbasierter Technologien zu rechnen. Bis zum Jahr 2030 ergibt sich aufgrund sinkender Kosten für erneuerbare Gase sektorübergreifend eine Reduktion der CO2-Verminderungskosten.
  • Thesis
    As electricity generation based on volatile renewable resources is subject to fluctuations, data with high temporal and spatial resolution on their availability is indispensable for integrating large shares of renewable capacities into energy infrastructures. The scope of the present doctoral thesis is to enhance the existing energy modelling environment REMix in terms of (i.) extending the geographic coverage of the potential assessment tool REMix-EnDaT from a European to a global scale, (ii.) adding a new plant siting optimization module REMix-PlaSMo, capable of assessing siting effects of renewable power plants on the portfolio output and (iii.) adding a new alternating current power transmission model between 30 European countries and CSP electricity imports from power plants located in North Africa and the Middle East via high voltage direct current links into the module REMix-OptiMo. With respect to the global potential assessment tool, a thorough investigation is carried out creating an hourly global inventory of the theoretical potentials of the major renewable resources solar irradiance, wind speed and river discharge at a spatial resolution of 0.45°x0.45°. A detailed global land use analysis determines eligible sites for the installation of renewable power plants. Detailed power plant models for PV, CSP, wind and hydro power allow for the assessment of power output, cost per kWh and respective full load hours taking into account the theoretical potentials, technological as well as economic data. The so-obtined tool REMix-EnDaT can be used as follows: First, as an assessment tool for arbitrary geographic locations, countries or world regions, deriving either site-specific or aggregated installable capacities, cost as well as full load hour potentials. Second, as a tool providing input data such as installable capacities and hourly renewable electricity generation for further assessments using the modules REMix-PlasMo and OptiMo. The plant siting tool REMix-PlaSMo yields results as to where the volatile power technologies photovoltaics and wind are to be located within a country in order to gain distinct effects on their aggregated power output. Three different modes are implemented: (a.) Optimized plant siting in order to obtain the cheapest generation cost, (b.) a minimization of the photovoltaic and wind portfolio output variance and (c.) a minimization of the residual load variance. The third fundamental addition to the REMix model is the amendment of the module REMix-OptiMo with a new power transmission model based on the DC load flow approximation. Moreover, electricity imports originating from concentrating solar power plants located in North Africa and the Middle East are now feasible. All of the new capabilities and extensions of REMix are employed in three case studies: In case study 1, using the module REMix-EnDaT, a global potential assessment is carried out for 10 OECD world regions, deriving installable capacities, cost and full load hours for PV, CSP, wind and hydro power. According to the latter, photovoltaics will represent the cheapest technology in 2050, an average of 1634 full load hours could lead to an electricity generation potential of some 5500 PWh. Although CSP also taps solar irradiance, restrictions in terms of suitable sites for erecting power plants are more severe. For that reason, the maximum potential amounts to some 1500 PWh. However, thermal energy storage can be used, which, according to this assessment, could lead to 5400 hours of full load operation. Onshore wind power could tap a potential of 717 PWh by 2050 with an average of 2200 full load hours while offshore, wind power plants could achieve a total power generation of 224 PWh with an average of 3000 full load hours. The electricity generation potential of hydro power exceeds 3 PWh, 4600 full load hours of operation are reached on average. In case study 2, using the module REMix-PlaSMo, an assessment for Morocco is carried out as to determine limits of volatile power generation in portfolios approaching full supply based on renewable power. The volatile generation technologies are strategically sited at specific locations to take advantage of available resources conditions. It could be shown that the cost optimal share of volatile power generation without considering storage or transmission grid extensions is one third. Moreover, the average power generation cost using a portfolio consisting of PV, CSP, wind and hydro power can be stabilized at about 10 €ct/kWh by the year 2050. In case study 3, using the module REMix-OptiMo, a validation of a TRANS-CSP scenario based upon high shares of renewable power generation is carried out. The optimization is conducted on an hourly basis using a least cost approach, thereby investigating if and how demand is met during each hour of the investigated year. It could be shown, that the assumed load can safely be met in all countries for each hour using the scenario's power plant portfolio. Furthermore, it was proven that dispatchable renewable power generation, in particular CSP imports to Europe, have a system stabilizing effect. Using the suggested concept, the utilization of the transfer capacities between countries would decrease until 2050.
  • Article
    The main objective of this research is to present a solid foundation of capex projections for the major solar energy technologies until the year 2030 for further analyses. The experience curve approach has been chosen for this capex assessment, which requires a good understanding of the projected total global installed capacities of the major solar energy technologies and the respective learning rates. A literature survey has been conducted for CSP tower, CSP trough, PV and Li-ion battery. Based on the literature survey a base case has been defined for all technologies and low growth and high growth cases for further sensitivity analyses. All results are shown in detail in the paper and a comparison to the expectation of a potentially major investor in all of these technologies confirmed the derived capex projections in this paper.
  • 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
    Saudi Arabia is in the midst of redefining the vision for the country's future and creating an economy that is not dependent on fossil fuels. This work presents a pathway for Saudi Arabia to transition from the 2015 power structure to a 100% renewable energy based system by 2050 and analyse the benefits of integrating the power sector with the growing desalination sector. It is found that Saudi Arabia can transition to a 100% renewable energy power system by 2040 whilst meeting the growing water demand through seawater reverse osmosis (SWRO) desalination plants. The dominating renewable energy sources are PV single-axis tracking and wind power plants with 210 GW and 133 GW, respectively. The levelised cost of electricity (LCOE) of the 2040 system is 48 €/MWh. By 2050, PV single-axis tracking dominates the power sector due to the further reduction in the capital costs alongside cost reductions in supporting battery technology. This results in 80% share of solar PV in the total electricity generation. Battery storage is required to meet the total electricity demand and by 2050, accounts for 48% of the total electricity demand. The LCOE is estimated at 38 €/MWh, required capacity of PV single-axis tracking is 369 GW and wind power plants 75 GW. In the integrated scenario, due to flexibility provided by the SWRO plants, there is a reduced demand for battery storage and power-togas (PtG) plants. In addition, the ratio of the energy curtailed to the total energy generated is lower in all time periods from 2020 to 2050, in the integrated scenario. As a result, the annual levelised costs of the integrated scenario is found to be 2%-4% less than the non-integrated scenario.
  • Article
    The Paris Agreement duly reflects the latest scientific understanding of systemic global warming risks. Limiting the anthropogenic temperature anomaly to 1.5–2 °C is possible, yet requires transformational change across the board of modernity.
  • Conference Paper
    The Middle East and North Africa (MENA) region, comprised of 19 countries, is currently facing a serious challenge to supply their growing economies with secure, affordable and clean electricity. The MENA region holds a high share of proven crude oil and natural gas reserves in the world. Further, it is predicted to have increasing population growth, energy demand, urbanization and industrialization, each of which necessitates a comparable expansion of infrastructure, resulting in further increased energy demand. When planning this expansion, the effects of climate change, land use change and desertification must be taken into account. The MENA region has an excellent potential of renewable energy (RE) resources, particularly solar PV and wind energy, which can evolve to be the main future energy sources in this area. In addition, the costs of RE are expected to decrease relative to conventional energy sources, making a transition to RE across the region economically feasible. The main objective of this paper is to assume a 100% RE-based system for the MENA region in 2030 and to evaluate its results from different perspectives. Three scenarios have been evaluated according to different high voltage direct current (HVDC) transmission grid development levels, including a region-wide, area-wide and integrated scenario. The levelized cost of electricity (LCOE) is found to be 61 €/MWhel in a decentralized scenario. However, it is observed that this amount decreases to 55 €/MWhel in a more centralized HVDC grid connected scenario. In the integrated scenario, which consists of industrial gas production and reverse osmosis water desalination demand, integration of new sectors provides the system with required flexibility and increases the efficiency of the usage of storage technologies. Therefore, the LCOE declines to 37 €/MWhel and the total electricity generation is decreased by 6% in the system compared to the non-integrated sectors. The results clearly show that a 100% RE-based system is feasible and a real policy option.
  • Conference Paper
    With growing demand for transportation fuels such as diesel and concerns about climate change, this paper introduces a new value chain design for transportation fuels and a respective business case taking into account hybrid PV-Wind power plants. The value chain is based on renewable electricity (RE) converted by power-to-liquids (PtL) facilities into synthetic fuels, mainly diesel. This RE-diesel can be shipped to everywhere in the world. The calculations for the hybrid PV-Wind power plants, electrolysis and hydrogen-to-liquids (H2tL) are done based on annual full load hours (FLh). A combination of 5 GWp PV single-axis tracking and wind onshore power have been applied. Results show that the proposed RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 79-135 USD/barrel (0.44 – 0.75 €/l of diesel production cost), depending on the chosen specific value chain and assumptions for cost of capital, available oxygen sales and CO2 emission costs. RE-diesel could become competitive to conventional diesel from an economic perspective, while removing environmental concerns. The cost range would be an upper limit for the conventional diesel price in the long-term and RE-diesel can become competitive whenever the fossil fuel prices are higher than the level mentioned and the cost assumptions expected for the year 2030 are achieved. A sensitivity analysis indicates that the RE-PtL value chain needs to be located at the best complementing solar and wind sites in the world combined with a de-risking strategy and a special focus on mid to long-term electrolyser and H2tL efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of terawatts.
  • Article
    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.
  • Article
    Full-text available
    In less than a decade, biofuels transitioned from being a socially and politically acceptable alternative to conventional transport fuels to a deeply contested solution. Claims of land grabs, forest loss and food riots emerged to undermine the sustainability rationale that originally motivated their adoption. One of the early controversies to hit biofuels was that of food versus fuel. This framing drew attention not only to the competing uses of land i.e. for food or for fuel, but also to the impacts of consumption on marginalised people, particularly in the global South. While the debate has provided a useful hook on which to hang criticisms of increased demand for biofuels, it also masks a more complex reality. In particular, the multifaceted and global linkages between the stewardship of land, the food sector, and global energy policies. In this paper, we use the debate on food versus fuel as a lens to examine the interdependencies between the multiple end-uses of feedstocks and the multifunctionality of land. Revealing a more nuanced understanding of the realities of agricultural networks, land use conflicts and the values of the people managing land, we argue that the simplification achieved by food versus fuel, although effective in generating public resonance that has filtered into political response, has failed to capture much that is at the heart of the issue.