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Applied Energy xxx (xxxx) xxx
Please cite this article as: Mahdi Fasihi, Applied Energy, https://doi.org/10.1016/j.apenergy.2020.116170
0306-2619/© 2020 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).
Global potential of green ammonia based on hybrid PV-wind power plants 
Mahdi Fasihi a,*, Robert Weiss b, Jouni Savolainen c, Christian Breyer a 
a LUT University, Yliopistonkatu 34, 53850 Lappeenranta, Finland 
b VTT Technical Research Centre of Finland, Vuorimiehentie 3, 02044 Espoo, Finland 
c Semantum Ltd., Tekniikantie 14, 02150 Espoo, Finland 
H I G H L I G H T S 
• Green ammonia can be produced for 370–450 €/tonne in all continents by 2030. 
• The production costs at the best sites could decline to 285–350 €/tNH3 by 2050. 
• Coal-based ammonia in China is the first to be substituted by green ammonia. 
• Flexible synthesis units have a major role in low-cost green ammonia production. 
• PV is a dominating source of power supply to islanded plants in most of the world. 
A R T I C L E I N F O 
Keywords: 
Hybrid PV–wind 
Battery 
Power-to-Ammonia (PtA) 
Power-based chemicals 
Power-to-X 
Energy economics 
A B S T R A C T 
Ammonia is one of the most commonly used feedstock chemicals globally. Therefore, decarbonisation of 
ammonia production is of high relevance towards achieving a carbon neutral energy system. This study in-
vestigates the global potential of green ammonia production from semi-flexible ammonia plants utilising a cost- 
optimised configuration of hybrid PV-wind power plants, as well as conversion and balancing technologies. The 
global weather data used is on an hourly time scale and 0.45◦ × 0.45◦ spatial resolution. The results show that, 
by 2030, solar PV would be the dominating electricity generation technology in most parts of the world, and the 
role of batteries would be limited, while no significant role is found for hydrogen-fuelled gas turbines. Green 
ammonia could be generated at the best sites in the world for a cost range of 440–630, 345–420, 300–330 and 
260–290 €/tNH3 in 2020, 2030, 2040 and 2050, respectively, for a weighted average capital cost of 7%. 
Comparing this to the decade-average fossil-based ammonia cost of 300–350 €/t, green ammonia could become 
cost-competitive in niche markets by 2030, and substitute fossil-based ammonia globally at current cost levels. A 
possible cost decline of natural gas and consequently fossil-based ammonia could be fully neutralised by 
greenhouse gas emissions cost of about 75 €/tCO2 by 2040. By 2040, green ammonia in China would be lower in 
cost than ammonia from new coal-based plants, even at the lowest coal prices and no greenhouse gas emissions 
cost. The difference in green ammonia production at the least-cost sites in the world’s nine major regions is less 
than 50 €/tNH3 by 2040. Thus, ammonia shipping cost could limit intercontinental trading and favour local or 
regional production beyond 2040. 
1. Introduction 
The global ammonia production reached 176 million metric tons in 
2016, of which about 79% was used in the production of fertilisers [1], 
and the remaining for industrial applications, such as manufacturing of 
plastics, fibres, explosives, amines, amides and other organic nitrogen 
compounds [2]. Being associated with food supply of a growing popu-
lation, the ammonia demand experienced an average growth of 1.9% 
from 2006 to 2016 and is expected to continue this trend during the 
coming decades [1]. For a century, industrial ammonia production has 
been mainly based on thermochemical conversion of hydrogen and ni-
trogen through the Haber-Bosch process [3]. While nitrogen is captured 
from air, the required hydrogen is almost entirely based on fossil fuels. 
About 83% of required hydrogen is produced by integrated steam 
reforming of natural gas, naphtha, liquefied petroleum gas (LPG) and 
refinery gas, and approximately 16.5% is produced by partial oxidation 
of fossil coal or heavy hydrocarbons such as heavy oil [2,4]. Currently, 
* Corresponding author. 
E-mail address: mahdi.fasihi@lut.fi (M. Fasihi). 
Contents lists available at ScienceDirect 
Applied Energy 
journal homepage: www.elsevier.com/locate/apenergy 
https://doi.org/10.1016/j.apenergy.2020.116170 
Received 3 May 2020; Received in revised form 27 September 2020; Accepted 30 October 2020 
mailto:mahdi.fasihi@lut.fi
www.sciencedirect.com/science/journal/0306-2619
https://www.elsevier.com/locate/apenergy
10.1016/j.apenergy.2020.116170
10.1016/j.apenergy.2020.116170
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Applied Energy xxx (xxxx) xxx
2
the fossil-feedstock for ammonia production, together with auxiliary 
fossil-based electricity, contribute more than 1.0% of the global green-
house gas (GHG) emissions [5]. This is considerable amount of GHG 
emissions from a single non-carbon compound. Thus, decarbonisation of 
ammonia production is of high relevance to meet the targets of the Paris 
Agreement in limiting global warming [6,7]. 
The research on sustainable ammonia production is divided into 
three major groups. The first group is focused on cleaner ammonia 
production from fossil fuels (commonly known as blue ammonia) 
through broadly discussed carbon capture from CO2 emitting processes 
[8,9]. However, this method would still face sustainability issues due to 
efficiency losses in carbon capture and concerns about geological limits 
for sustainable and permanent CO2 storage. The second group focusses 
on the use of renewable energy and feedstock for ammonia production 
(commonly known as green ammonia), which is the focus of this study. 
The third group focusses on the new synthesis methods such as elec-
trochemical ammonia production to simplify the process and increase 
the efficiency [10–12], however, such technologies are not yet 
commercially available. 
Using commercially available technologies, the ammonia production 
can be fully decarbonised using renewable electricity (RE) for hydrogen 
generation (mainly via water electrolysis) and other processes, elimi-
nating carbon from the ammonia production cycle. Hydropower-based 
ammonia production has a commercial history going back to 1920s 
[3,13], which, later became less cost-competitive and was discontinued 
due to the cost decline of natural gas. However, with the current ongoing 
cost decline of solar photovoltaic (PV) and wind power, RE-based 
ammonia is regaining attention. Proton Venture already offers small- 
scale Power-to-Ammonia systems up to 20,000 tNH3/a net capacity 
[14] with solar and wind as the source of power. To prepare for large- 
scale green ammonia production, Yara will install and test a new 5 
GW alkaline water electrolyser to supply 1% of hydrogen to their con-
ventional ammonia plant in Porsgrunn, Norway [15]. In addition, a 5 
bUSD agreement has been signed for the development of a first large- 
scale Power-to-Ammonia plant based on hybrid PV-wind power supply 
in Saudi Arabia [16]. 
From recent academic research, Tunå et al. [17] investigated the cost 
of biogas-, biomass- and electrolyser-based ammonia production (via 
wind-supplied grid electricity) on a range of small-scale plants. Morgan 
[18] performed a detailed techno-economic analysis of ammonia 
production by offshore wind and grid electricity as the balancing solu-
tion in the US. Later, Morgan et al. [19,20] did a case study for Power-to- 
Ammonia (as a feedstock, fuel or storage medium) in a remote US island. 
Frattini et al. [21] evaluated energy efficiency of biogas, biomass and 
solar-wind electricity to ammonia and concluded lowest energy demand 
for the solar-wind case. Nayak-Luke et al. [22] modelled a green 
ammonia system based on fixed capacities of solar and wind power in 
Shetland, Scotland and sized other units accordingly. This study used 
fuel cells as the only power balancing technology. Armijo andPhilibert 
[23] modelled the production of green ammonia based on a cost- 
optimised combination of a flexible ammonia synthesis unit, solar and 
wind energy in 4 locations in Chile and Argentina. The University of 
Minnesota together with the U.S. Department of Energy’s National 
Renewable Energy Laboratory (NREL) and Proton OnSite are developing 
a small-scale wind-powered ammonia production [24]. 
The above-mentioned studies advance the knowledge on Power-to- 
Ammonia; however, they are limited in several aspects, namely stud-
ied locations, applied technologies, estimation of production potential 
and time scale. With the ongoing steep decline in the cost of PV and 
battery systems [25,26], they are unneglectable parts of any energy 
system modelling. In this study, a model is provided that evaluates the 
cost-optimised configuration of solar PV, wind, as well as hourly and 
seasonal balancing technologies for islanded ammonia production 
globally based on actual hourly weather data in a 0.45◦ × 0.45◦ spatial 
resolution. To the knowledge of the authors, this is the first global green 
ammonia atlas. The ammonia production cost and the production chain 
configuration are evaluated based on the projected techno-economic 
advancements from 2020 to 2050 in 10-year time steps (Appendix A), 
both at the electricity generation site (Onsite Scenario) and at the nearest 
coast for possible export option (Coastal Scenario). 
The cost-competitiveness of RE-based ammonia with fossil-based 
ammonia is evaluated at different natural gas prices and CO2 emission 
costs. Once ammonia is decoupled from the fossil fuels, its applications 
could well expand beyond fertilisers, to a fuel or storage medium. 
Grinberg Dana et al. [27] evaluated the Power-to-Fuel-to-Power effi-
ciency of ammonia and alternative fuels. Wang et al. [28] and Elishav 
et al. [29] evaluated and compared the energy storage cost of ammonia 
and an aqueous solution of ammonium hydroxide and urea with alter-
natives such as lithium-ion battery, compressed air, pumped hydro and 
methanol. Valera-Medina et al. [30] reviewed the concept of ammonia 
for producing power. Wang et al. [31] analysed the feasibility of 
ammonia production using excess electricity from large-scale PV sys-
tems in China. Ikäheimo et al. [32] investigated the multidimensional 
role of Power-to-Ammonia as a fuel and a storage medium for a fully 
renewable power and heat system in the future for Northern Europe. 
Application of ammonia as a fuel or a storage medium could increase its 
demand exponentially. 
In summary, the main objectives of this study are: firstly, creating a 
global cost-capacity atlas of green ammonia; secondly, analysis of a cost- 
optimised power-to-ammonia plant configurations and identifying 
major balancing technologies globally in high spatial resolution; and 
thirdly, identifying time and regions for fuel parity of green ammonia 
with fossil-based ammonia and evaluating potential importer and 
exporter regions. 
The applied methods are explained in Section 2. Results are pre-
sented and discussed in Section 3. Conclusions are drawn in Section 4. 
2. Methods 
2.1. Ammonia synthesis unit 
A Haber-Bosch ammonia (NH3) plant produces anhydrous liquid 
ammonia from hydrogen (H2) and nitrogen (N2). In a NH3 plant, the 
Haber-Bosch synthesis itself takes place in a reactor within a synthesis 
loop. The synthesis is a catalytic reaction within a pressure range of 
100–250 bar and temperature range of 350–550 ◦C [4]. In this study, a 
Nomenclature 
a year 
ASU Air Separation Unit 
capex Capital Expenditures 
FLh Full Load hours 
GHG Greenhouse Gas 
HHV Higher Heating Value 
HVAC High-Voltage Alternating Current 
HVDC High-Voltage Direct Current 
LCOE Levelised Cost of Electricity 
opex Operating Expenditures 
PV Photovoltaic 
RE Renewable Electricity 
SMR Steam Methane Reforming 
WACC Weighted Average Cost of Capital 
Subscripts 
el electricity 
fix fixed 
th thermal 
var variable 
M. Fasihi et al. 
Applied Energy xxx (xxxx) xxx
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temperature of 480 ◦C and a pressure of 150 bar for the Haber-Bosch 
synthesis unit are considered based on Morgan [18]. Flexibility of the 
synthesis unit could minimise power and hydrogen balancing demand, 
and consequently the overall cost in regions that do not have access to 
relatively stable power supply or cheap geological hydrogen storage. 
Armijo and Philibert [23] considered two scenarios with 40% and 80% 
flexibility with maximum 20% ramp up and ramp down rates per hour, 
based on the literature and interviews with manufacturers. In this study, 
after consulting industry experts, a minimum load of 50%, a ramp up 
limit of 2% and a ramp down limit of 20% per hour are considered for the 
ammonia synthesis unit coupled with the air separation unit at no major 
additional cost or efficiency loss. Morgan [18] considers a 100% mass 
conversion factor for the overall reaction (Eq. (1)), which implies the 
possibility of full conversion of feedstock to final product. However, in a 
conservative approach, a conversion factor of 99% is assumed in this 
study to account for potential losses, especially for a plant based on 
variable load operation, which leads to 179.4 kgH2 and 830.7 kgN2 con-
sumption per ton of ammonia production. The ammonia production re-
action is exothermic, and the net recoverable heat depends on the plant’s 
configuration. No usage is specified for the excess heat in this study. 
3H2 (g)+N2 (g)→2NH3 (g), Δf H
◦
= − 45.64kJ/molNH3 (1) 
Based on Morgan [18], modified to a 99% overall conversion factor 
for an all-electric NH3 plant, the synthesis loop would require 648 kWh/ 
tNH3, including the power demand for compression of input H2 and N2 
(from 1 and 8 bar, respectively) to reactor’s pressure of 150 bar (abso-
lute pressure, also known as bara). The cryogenic air separation unit 
(ASU) would require 90 kWh/tNH3 for capturing the required N2 from 
air. The power requirement for ammonia storage would be negligible. 
Thus, the total direct electricity demand would be 738 kWh/tNH3. It is 
assumed that the specific electricity consumption remains constant for 
different plant sizes. 
The scale has an impact on the capital expenditure (capex) of a Haber- 
Bosch NH3 plant. Typical modern large-scale NH3 plants have production 
capacity of 1000–2000 tons of NH3 per day [2], and new plants are 
designed for capacities reaching 3000 tons of NH3 per day equivalent to 
1,000,000 t/year. Power laws were fitted to the capex estimations in 
USD2010 for the synthesis loop, ASU and ammonia storage in respective 
capacity units presented in Morgan [18] as shown in Eqs. (2.1)–(2.3). 
Capexsynthesis loop = 23850000∙Capacity(tNH3day )
− 1.340 + 173500 (2.1) 
CapexASU = 1606000∙Capacity(tN2day)
− 0.6249 + 9318 (2.2) 
CapexNH3 storage = 46600∙Capacity(tNH3) − 0.8636 + 536.9 (2.3) 
The overall capex of the ammonia plant is calculated by sizing the 
ASU to the synthesis loop’s nitrogen demand and considering 30 days of 
ammonia storage. Then the values are converted from USD2010 to €2019, 
by considering a cumulative inflation of 17.24% on USD from 2010 to 
2019 [33] and then applying an USD/€ exchange rate of 1.12 in 2019 
[34]. The resulted overall capex of the ammonia plant is illustrated in 
Fig. 1 for a capacity range of 50,000 to 1,000,000 tNH3/a. While the 
illustrated capex decline is in line with the concept of economies of scale 
for the ammonia plants, small-scale ammonia plants could remain 
competitive through a modular design, wider range of potential investors 
and elimination of product transportation, as pointed out by Brown [35]. 
2.2. Power-to-Ammonia value chain and scenarios 
Two scenarios (Onsite and Coastal) are modelled to represent the 
potential oflocal consumption and export cases. The applied methods 
are based on Fasihi and Breyer [36] which can be referred to for a more 
extensive model description. 
In the Onsite Scenario, illustrated in Fig. 2, the ammonia plant is at the 
electricity generation site. Electricity is generated by a cost-optimised 
0
100
200
300
400
500
600
700
800
900
50 15
0
25
0
35
0
45
0
55
0
65
0
75
0
85
0
95
0
Ca
pe
x 
(€
/t
N
H
3.
a)
Capacity (ktNH3/a)
NH3 synthesis loop
Air Separation Unit
NH3 storage
Fig. 1. Capex development of all-electric NH3 plants, excluding the electrolysers. 
Water 
Electrolyser
Semi-flexible
ASU (N2 capture), 
feed gases 
compressors and 
NH3 synthesis unit
H
2
Com
p.
H2 underground pipeline
H2 lined rock cavern
H2 salt cavern
PV
fixed ti lted
PV
single-axis 
tracking
Wind
onshore
Battery 
interface
Battery
storage
NH3
storage
LT heatO2
HT heat
Water
H
2-
O
CG
T
H
2-
CC
G
T
curtailed
Baseload
NH3 supply
Fig. 2. Power-to-Ammonia Onsite model configuration. Commercially available hydrogen-fuelled gas turbines are considered from 2030 onwards. Abbreviations: H2- 
fueled open cycle gas turbine, H2-OCGT, H2-fueled combined cycle gas turbine, H2-CCGT, hydrogen compressor, H2 Comp, high temperature heat, HT heat, low 
temperature heat, LT heat. Green and blue lines represent electricity and hydrogen flow, respectively. 
M. Fasihi et al. 
Applied Energy xxx (xxxx) xxx
4
configuration of fixed tilted PV, single-axis tracking PV and wind tur-
bines. Hydrogen is generated by a cluster of flexible alkaline water 
electrolysers [37] at 30 bar, which can be directed to the ammonia plant. 
The excess hydrogen generation is stored in locally available hydrogen 
storage options via hydrogen compressors [38,39] to balance hydrogen 
supply to the ammonia plant at hours with direct hydrogen deficit. The 
potential hydrogen storage options considered in the model are man- 
made salt cavern and rock cavern at a range of 60–200 bar operating 
pressure and underground pipeline storage at 20–200 bar pressure. To 
maintain the minimum pressure, salt and rock cavern require cushion 
gas at about 30% of their gross capacity or 43% of operational capacity 
[40]. The cost of cushion gas is included in the salt and rock cavern 
capex. The maximum hourly charge or discharge of salt and rock cavern 
is limited to 8% per day (0.33% per hour) of operational capacity to 
avoid extra tension on walls due to rapid pressure change. For under-
ground pipeline, the maximum hourly charge or discharge is limited to 
16.67% of the operational capacity (minimum 12 h for full charge or 
discharge) for the sake of temperature change management [40]. While 
salt cavern and to some extent rock cavern are relatively cheaper options 
for large-scale and seasonal hydrogen storage, their availability is 
limited around the globe. Data on suitable regions for salt or rock cavern 
storage are taken from Aghahosseini and Breyer [41] and are provided 
in Fig. S10. The compressors’ electricity demand for adiabatic 
compression of hydrogen in the range of 30 to 200 bar is 0.053 kWh/ 
kWhH2,HHV, according to Makridis [42]. However, during most hours of 
a year, storage level would not be at the maximum capacity and pres-
sure. Therefore, hydrogen injection to the storage can be done at a lower 
compression range by compressors, representing a lower electricity 
demand. In this study, average power consumption at 75% of a full 
range compression is considered. Thus, the compressors’ electricity 
consumption is fixed at 0.04 kWh/kWhH2,HHV. The compressor capex is 
based on 150 MWH2,LHV units, calculated according to the capex of 6 
MWH2,LHV units by Grond et al. [38] and a scaling factor of 0.67 based on 
Hannula [43]. Electrical storage is included in the model, primarily to 
supply electricity to the ammonia plant (including the air separation 
unit), as well as increasing the operating hours of the electrolysers if it is 
part of a cost-optimised solution. The electricity storage system consists 
of an independently scalable battery interface and battery storage, as 
well as open cycle and combined cycle hydrogen-fuelled gas turbines as 
seasonal balancing technology. Major gas turbine manufacturers have 
set a target to make hydrogen-fuelled gas turbines commercially avail-
able by 2030 [44,45]. Thus, the power-to-hydrogen-to-power (PtH2tP) 
system is included in the model from 2030 onwards. In the Onsite Sce-
nario, capex is based on a medium sized (400,000 tNH3/a) plant to match 
the local or regional ammonia demand. However, to supply a fixed de-
mand, the actual installed capacity could be higher in different locations 
depending on the capacity factor of a semi-flexible ammonia plant. The 
additional capex reduction in such a case is not included and it is 
assumed to be offset by the potential additional costs of flexible opera-
tions. The cost of fresh water demineralisation system, which is esti-
mated to be about half of the seawater desalination cost, is negligible 
and is assumed to be included in the cost of electrolyser package. 
Whether fresh water would be available locally or supplied by desali-
nated water from nearest coast, the additional cost of water supply is 
negligible according to Fasihi and Breyer [36], and thus it is not 
included in the model. More information about water supply by desa-
lination plants is provided in the Supplementary Information. 
The above-mentioned setup is rather conservative. The electricity 
demand from the hydrogen compressors coupled to an ammonia plant is 
calculated from 1 bar, while the hydrogen supplied by the electrolysers 
and hydrogen storage options would be at higher pressures, leading to a 
lower actual electricity demand for hydrogen compression in the syn-
thesis loop. Moreover, the electrolyser efficiency at part-load operation 
is higher [22] which is not considered in this study. 
In the Coastal Scenario, the nearest node from ocean shoreline to the 
power plant site is identified and the ammonia plant is located at a 
neighbouring coastal node of the ocean node. If there are more than one 
costal node around the nearest ocean node, the chosen coastal node is 
prioritised based on availability of firstly salt cavern or secondly rock 
cavern among the nominated costal nodes, in order to increase available 
low-cost hydrogen storage options at coast. The costal node is connected 
to the power plants via high-voltage alternating current (HVAC) and 
high-voltage direct current (HVDC) transmission lines. Considering the 
natural barriers, length of the power lines is set at 110% of the direct 
distance to the nearest coast. Electricity can be optionally balanced 
before the transmission lines via battery or PtH2tP technologies, as 
illustrated in Fig. 3. 
Water 
Electrolyser
PV
fixed tilted
PV
single-axis 
tracking
Wind
onshore
Battery 
interface
Battery
storage
H
2-
O
CG
T
H
2-
CC
G
T
curtailed
to electricity balancing 
and PtA plant at coast
H2
Comp.
AC/DC 
conv.
HVDC 
transmission line
DC/AC 
conv.
HVAC 
transmission line
Fig. 3. Configuration of power source, balancing and transmission option for the Coastal Scenario. Hydrogen-fuelled gas turbines are assumed from 2030 onwards. 
The potential impact of AC transformer is not considered. Abbreviations: photovoltaic, PV, compressor, comp., hydrogen-fuelled open cycle gas turbine, H2-OCGT, 
hydrogen-fuelled combined cycle gas turbine, H2-CCGT. Green and blue lines represent electricity and hydrogen flow, respectively. 
M. Fasihi et al.Applied Energy xxx (xxxx) xxx
5
The transportation of Onsite ammonia to the coast via pipeline is an 
other option for providing ammonia at the coast. This option was 
excluded from this study due to lack of access to high spatial resolution 
information about geological conditions which could impact the cost of 
ammonia pipeline significantly. 
The Eqs. (3) and (4) are used to calculate the levelised cost of energy 
(LCOE) for power plants and the subsequent value chains, based on 
NREL guidelines [46]. Abbreviations: applied technology, i, capital ex-
penditures, Capex, annual fixed operational expenditures, Opexfix, vari-
able operational expenditures, Opexvar, full load hours per year, FLh, fuel 
costs per unit of energy, fuel, efficiency of fuel convertor, η, annuity 
factor, crf, weighted average cost of capital, WACC, lifetime, N. The 
weighted average cost of capital (WACC) is set to 7% in all regions and 
simulations based on an equity share of 30% and an interest rate of 4% 
(excluding inflation) which would lead to a return on equity of 14%. All 
efficiency and capex numbers are based on the higher heating value 
(HHV), when applicable. 
crf =
WACC∙(1 + WACC)N
(1 + WACC)N − 1
(3) 
LCOEi =
Capexi∙crf + Opexi,fix
FLhi
+Opexi,var +
fuel
ηi
(4) 
The modelling is done in Matlab R2016a [47]. The hourly energy and 
mass balance in all scenarios are based on Eqs. (5.1)–(5.4) for electricity 
generators (fixed tilted and single-axis tracking PV, wind energy, battery 
power, H2-OCGT, H2-CCGT), electricity consumers (electrolyser, 
compressor, ammonia plant), battery storage charge and discharge, 
curtailed electricity, H2 generator (electrolyser), H2 consumers 
(compressor, H2-OCGT, H2-CCGT, ammonia plant), H2 storage options 
charge and discharge and electricity conversion and transmission tech-
nologies (AC/DC converter, HVAC, HVDC). Abbreviations: technology, 
tech, electricity, El, time, t, generation, gen, consumption, cons, battery, 
Batt, charge, char, discharge, disch, electricity curtailment, curt, Trans-
mission Line, TL. 
electricity balance,Onsite Scenario :
∑tech
t
Elgen,t − Battchar,t +Battdisch,t − Elcurt,t =
∑tech
t
Elcons,t (5.1) 
electricity balance,Coastal Scenario (before and after TL) :
∑tech
t
Elgen,t −
∑tech
t
Elcons,t − Battchar,t +Battdisch,t − Elcurt,t =
∑tech
t
TLin,t 
∑tech
t
TLin,t −
∑tech
t
TLloss,t =
∑tech
t
TLout,t 
∑tech
t
TLout,t =
∑tech
t
Elcons,t −
∑tech
t
Elgen,t +Battchar,t − Battdisch,t (5.2) 
hydrogen balance,Onsite Scenario :
∑tech
t
H2gen,t −
∑tech
t
H2storagechar,t+
∑tech
t
H2storagedisch,t=
∑tech
t
H2cons,t
(5.3) 
hydrogen balance, Coastal Scenario (before and after TL, separately) :
∑tech
t
H2gen,t −
∑tech
t
H2 storagechar,t +
∑tech
t
H2 storagedisch,t 
=
∑tech
t
H2cons,t (5.4) 
The state of charge (SoC) in storage facilities is formulated as in Eqs. 
(6.1) and (6.2), that take into account independently the hourly 
charging step losses, discharging step losses and hourly self-discharge of 
stored power, hydrogen or ammonia. In Appendix A, the total charge 
and discharge efficiency is defined as cycle efficiency. Abbreviations: 
storage state of charge, SoC, efficiency, eff, charge, char, discharge, disch, 
self--discharge, self-disch. 
∀t∈[2,8760]SoCt =SoCt− 1∙(1 − hourly selfdisch eff .)−
discht
discheff .
+chart∙char eff .
(6.1) 
SoCt=1 =SoC8760∙(1 − hourly selfdisch eff .)−
disch1
discheff .
+char1∙char eff .
(6.2) 
The cost-optimised configuration of components in achieving the 
above-mentioned energy and mass balance is found by Mosek [48] 
linear optimiser, as presented in Eq. (7). Abbreviations: installed ca-
pacity, instCap, generation, Gen. 
min
(
∑tech
i
(CAPEXi∙crfi + OPEXfixi)∙instCapi +OPEXvari∙Geni
)
(7) 
The world is divided into 0.45◦ × 0.45◦ nodes, representing an area 
range of 2500 km2 for nodes at the equator to less than 1200 km2 at 
regions beyond ±60◦ latitudes [36]. Average area coverage of 8.4 and 
75 MW/km2 is assumed for wind and PV power plants, respectively 
[49]. A 10% area limit is set for PV (total of fixed tilted and single-axis 
tracking) and a 10% area limit is set for wind power plant installations at 
each node. First, the optimisation is done for a relatively small-scale 
demand and then the system is scaled up until installed PV or wind 
capacity reaches to its area limit, representing the potential capacity of 
the cost-optimised configuration at each node. 
3. Results and discussion 
3.1. Levelised costs and annual production potential of ammonia 
The levelised cost of ammonia (LCOA) in a cost-optimised configu-
ration for the Onsite and Coastal Scenarios for the years 2020 to 2050 in 
10-year steps are illustrated in Fig. 4. For the Onsite Scenario in 2020, 
ammonia can be produced at best sites, such as Patagonia, Atacama 
Desert, Tibet and the Horn of Africa for costs below 600 €/tNH3. Theo-
retically, Greenland has the least cost production site in 2020, however 
its technical potential is very limited due to glaciers and permanent ice 
coverage in most parts of Greenland. In 2030, Atacama Desert, Horn of 
Africa, Yemen and Southwest Niger are the least cost regions at costs 
between 350 and 400 €/tNH3, while costs below 500 €/tNH3 become 
achievable in most regions of South America’s coastlines, Mexico, 
Central and Southwest US, Australia, Africa, MENA region and Central 
Asia. In Europe, such cost levels are achievable in Spain, Portugal, UK, 
Iceland and Denmark. In 2050, the production cost at best sites declines 
to about 260 to 300 €/tNH3, while costs below 450 €/tNH3 are achievable 
in most habitable regions of the world. The higher cost of ammonia 
production beyond ±60◦ latitudes is not of high relevance because ni-
trogen fertilisers demand, as the main ammonia consumer, is not sig-
nificant in those regions as shown for the case of Europe by EC [50] in 
Fig. S4. Armijo and Philibert [23] report on a production cost below 500 
USD/tNH3 in near-term at the vicinity of Atacama Desert, which is 
cheaper than the calculated production cost of about 550–600 €/tNH3 in 
2020 in this study. While these two studies consider a WACC of 7% and 
almost equal capex for electrolyser, Armijo and Philibert [23] consider 
higher PV capex which is compensated by higher electrolyser efficiency. 
However, considering the major differences, Armijo and Philibert [23] 
consider lower electrolyser opex, lower synthesis unit capex and opex, as 
well as a higher ramp up rate that lead to lower ammonia production 
cost. 
For the Coastal Scenario, the cost of ammonia from remote areas is 
usually relatively higher, as the cost of delivered electricity to the coast 
increases by distance. One exception is when a node with relatively 
strong seasonality of power supply does not have access to a geological 
hydrogen storage onsite but has access to cheap storage option at the 
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coastal node. Consequently, the cost decline by access to cheap 
hydrogen storage at coast could compensate the additional cost of the 
transmission lines. Thus, hydrogen pipelines to sites of accessible salt 
cavern hydrogen storage may economically pay off, even for distances of 
some hundreds of kilometres. At about 1000 km distance, the additional 
cost of costal ammonia compared to the Onsite Scenario would increase 
from about 10% in 2020 to 30–40% in 2050, depending on the region, 
while the absolute cost difference decreases to 40–100 €/tNH3 in 2050 
which could make low-cost ammonia at remote areas favourable if the 
local production is significantly more expensive. 
The area coverage of individual PV and wind is limited to 10% of the 
area within each node. Accordingly, the cost-optimal systemcould have 
an area coverage of 10–20% depending on the ratio of installed tech-
nologies. The potential optimal capacity at PV-dominated regions is 
higher due to higher annual electricity generation capacity per area of 
PV compared to wind turbines. As illustrated in Fig. 5, the highest 
optimal capacity of 1.7–2.5 MtNH3/a per 1000 km2 is observed at the 
Atacama Desert, Northern and Western Australia, Arabian peninsula, 
Tibet and most of Africa. For the Costal Scenario, the optimal capacity 
decreases due to additional efficiency losses. 
While an availability factor of 91% (8000 FLh) is considered for the 
ammonia synthesis unit, the semi-flexible plant shows a capacity factor 
of 70–91% around the globe in 2030, with higher range in regions with 
relatively seasonally stable PV-based power supply or access to 
relatively cheap geological hydrogen storage as shown in Fig. S16. 
Consequently, the required ammonia storage for baseload supply of 
ammonia throughout the year is zero to less than 30 days of baseload 
production in most parts of the world, as illustrated in Fig. S16. 
In Fig. 6, the global optimal generation potential from Fig. 5 are 
sorted based on the ammonia production cost, as generation capacity at 
least cost sites is more desired. Although the global ammonia production 
was about 176 million tons in 2016 [1], here the ammonia production 
cost for up to 10 Gt/a capacity has been discussed. The allocated global 
Fig. 4. Levelised cost of ammonia Onsite (left) and Coastal (right) for 2020 (top), 2030 (upper centre), 2040 (lower centre) and 2050 (bottom). 
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generation capacity is less than 10% of the global generation potential 
(with partial use of area in respective nodes) but offers more than 50 
times the required capacity at multiple regions in response to un-
certainties regarding the availability of land at the least cost sites. 
However, expansion of ammonia applications as a fuel could increase 
the demand exponentially. In 2020, the first 1–10 GtNH3/a could be 
produced at about 440–630 €/tNH3, while the production cost for the 
same annual capacity declines to 345–420, 300–330 and 260–290 
€/tNH3 in 2030, 2040 and 2050, respectively. In 2020, the least cost 
Coastal ammonia production is slightly cheaper than the least cost Onsite 
ammonia. This is because in 2020 Onsite scenario, some of the least cost 
sites are close to the coastline and the additional cost of transmission 
lines to the coast is negligible for the respective sites in the Coastal 
scenario, while they benefit from a cheaper synthesis unit due to the 
selection of larger plants for Coastal scenario and economies of scale. 
The production of 10 GtNH3 for Coastal scenario in 2030 and 2050 would 
be up to 35 and 20 €/tNH3 more expensive than the respective cumula-
tive capacity in Onsite scenario. Detailed regional cost analysis, cost 
comparison to conventional ammonia, fuel parity and impact of CO2 
emissions cost are discussed later in this section. 
3.2. Technology mix of cost-optimised systems 
The global results for 2030 and 2050 are provided and analysed in 
this section for better understanding of the global variation of major 
components in a cost-optimised system. Figures for 2020 and 2040 are 
available in the Supplementary Data (Figs. S5–S15). 
As shown in Fig. 7, by 2030, PV is the dominating electricity supply 
technology to RE-based ammonia plants in most parts of the world with 
the exception of Patagonia, Northern Canada, Iceland, UK and coastal 
lines of Western Europe, which are all excellent wind sites. The share of 
Fig. 5. Power-to-Ammonia optimal capacity potential (top) and generation potential (bottom) for Onsite (left) and Coastal (right) scenarios in 2030 with 10% land 
use limit for PV and wind power plants per 1000 km2. 
Fig. 6. Industrial cost curves for Power-to-Ammonia, based on cost-optimised hybrid PV-wind power plants for the period 2020 to 2050. 
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Fig. 7. Ratio of PV to hybrid PV-wind installed capacity for ammonia Onsite (left) and Coastal (right) for 2030 (top) and 2050 (bottom). 
Fig. 8. Ratio of battery discharge to total electricity demand (TED) onsite for ammonia Onsite (top), before transmission lines for ammonia Coastal (middle) and after 
transmission lines for ammonia Coastal (bottom) for 2030 (left) and 2050 (right). 
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PV further increases by 2050 due to a sharper projected cost decline. 
Low-cost PV and battery fully eliminate wind electricity from the power 
supply to islanded Power-to-Ammonia plants in Africa. In the Coastal 
Scenario, the ratio of wind power is relatively higher in remote areas, as 
higher FLh of wind reduces the cost of electricity transmission lines. 
As illustrated in Fig. 8, the share of battery discharge to total elec-
tricity demand (TED, defined as electricity demand by ammonia syn-
thesis unit and water electrolyser for feedstock hydrogen, excluding the 
hydrogen as fuel for gas turbines) remains at about 3.5–4.5% in PV- 
dominated regions for the Onsite Scenario, which is mainly to supply 
direct electricity demand for the air separation unit and the ammonia 
synthesis plant. The role of batteries is significantly lower in wind 
dominated regions, such as Patagonia, due to the availability of mini-
mum electricity demand for a longer time throughout the year. In the 
Coastal Scenario, batteries have a significant role in balancing electricity 
supply before the transmission line (bTL) and would supply 40–55% of 
total electricity demand for distances beyond 1500 km in 2050. The role 
of batteries is relatively smaller in 2030 due to its higher cost. With 
supply of less than 0.1% of TED, the role of batteries after the trans-
mission lines (aTL) is almost negligible. 
The role of gas turbines is marginal in the Onsite scenario or after 
transmission lines in the Coastal scenario and is up to 1% of the total 
electricity demand in regions beyond ±60◦ latitudes (Fig. 9). The 
electricity generated by gas turbines is only used to supply the direct 
electricity demand by the synthesis unit and does not feed into the 
electrolyser due to additional efficiency loss. On the other hand, gas 
turbines before the transmission lines in the Coastal scenario have a 
relatively stronger role in some regions with significant variability of 
power supply, but access to geological hydrogen storage onsite and not 
at the coast. In such conditions, gas turbines before the transmission 
lines mainly firm the direct electricity demand by the synthesis unit at 
the coast. In some regions of Northeastern Russia, with high seasonality 
of power supply but access to geological hydrogen storage, gas turbines 
before the transmission lines also contribute to power supply to the 
electrolysers at the coast. Nevertheless, these are some of the most 
expensive regions for synthetic fuels production in the world. Thus, the 
role of H2-fuelled gas turbines for ammonia production by semi-flexible 
synthesis units in low cost regions would remain zero to marginal. 
As shown in Fig. 10, HVAC is the dominating electricity transmission 
technology for distances up to 1500 in PV-dominated regions in 2030. 
Such a HVACpenetration rate is about 50% higher than those for Coastal 
baseload hydrogen by Fasihi and Breyer [36], which is due to a lower PV 
cost assumption used in this study based on a value between ETIP-PV 
[25] and Vartiainen et al. [26] for the years until 2030 and then fully 
following Vartiainen et al. [26], which makes higher efficiency losses 
less relevant. In regions with a high share of wind, such as central US, the 
Fig. 9. Ratio of hydrogen-fuelled gas turbines (CCGT and OCGT) generation to total electricity demand (TED) for ammonia Onsite (top), before transmission lines for 
ammonia Coastal (middle) and after transmission lines (bottom) for ammonia Onsite for 2030 (left) and 2050 (right). 
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FLh of input electricity to the transmission lines is relatively higher 
which reduces HVAC competitiveness to about 1000 km. In 2050, share 
of HVAC increases in the US as the share of PV increases. In PV- 
dominated central Africa, share of HVAC decreases from 2030 to 
2050, because batteries are cheaper in 2050 and more are installed 
before the transmission lines which increases the LCOE and FLh of input 
electricity to the transmission lines which in return increases the suit-
ability of more efficient HVDC transmission lines. Even at 2000 km, a 
small share of HVAC still exists which is for electricity transmission at 
peak hours. 
The overall efficiency of a baseload Power-to-Ammonia plant could 
be 61% and 66% (HHV) in 2030 and 2050, respectively. The higher 
efficiency in 2050 is because of the projected efficiency gain by water 
electrolysers stated in Appendix A. However, as shown in Fig. 11, the 
overall efficiency of hybrid PV-wind Power-to-Ammonia Onsite in 2030 
is about 50–58% worldwide. The additional losses stand for curtailment, 
losses in the battery and power-to-hydrogen-to-power cycle, as well as 
the electricity demand of the hydrogen compressor. The increase in the 
overall efficiency of Onsite Power-to-Ammonia in 2050 is not as strong as 
the efficiency gain by water electrolysers as higher levels of curtailment 
become a part of the cost-optimised solution (Fig. S9) due to lower 
electricity generation costs. In the Coastal Scenario, the overall efficiency 
could be as low as 40% in 2030 at far remote areas, due to higher 
curtailment and battery efficiency losses before the transmission lines, 
as well as losses in the transmission lines and conditional AC/DC con-
verter stations. The overall efficiency of Coastal Power-to-Ammonia in-
creases in 2050, due to more efficient electrolysers, as well as increased 
role of batteries with higher efficiency and more efficient HVDC lines. 
3.3. Sensitivity analyses 
The technical and financial assumptions in any global study include 
some uncertainty regarding long-term projections and regional opera-
tional condition which are not considered in the presented global sim-
ulations. Thus, a series of sensitivity analyses has been performed. In 
each sensitivity analysis, only one parameter is diverged from its base 
value. 
While all the simulations in this study are done based on a global 
average WACC of 7%, the local WACC in most countries would be within 
a range of 5–9% and long-term WACC projections are inherently un-
certain [51]. A WACC of 5% is possible in some parts of the world and 
more regions are expected to adopt lower WACC in long term as in-
vestment risks decline by maturing and scaling of RE-based technolo-
gies. An absolute 2% change in WACC would affect the ammonia 
Fig. 10. Ratio of HVAC to total HVAC and HVDC capacity for Coastal ammonia in 2030 (left) and 2050 (right). 
Fig. 11. Power-to-Ammonia overall efficiency Onsite (left) and Coastal (right) for 2030 (top) and 2050 (bottom). 
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production cost by about 14–15% in comparison to 7% WACC in 2030, 
as illustrated in Fig. 12. 
The impact of a 10% change in the capex of major electricity supply 
technologies (PV, wind and battery), with fixed absolute opex, on final 
cost of Onsite ammonia in 2030 is illustrated in Fig. 13. A 10% change in 
the capex of wind and PV power plants affects the overall cost of RE- 
based ammonia by about 0–5% and 0–4%, depending on the share of 
PV and wind in the electricity supply system. A 10% change in the capex 
of battery has no significant impact on the cost of ammonia, as its role is 
mainly limited to balancing minor direct electricity demand by the air 
separation unit and the ammonia synthesis unit. In all cases, the impact 
is minimised by system reconfiguration based on the applied cost 
assumptions. 
The capex curve in Fig. 1 is based on a baseload RE-based ammonia 
plant configuration. Although literature and interviews with experts 
suggest that moderate flexibility can be achieved for ammonia plants at 
no significant additional cost, a 10% change in the capex of the ammonia 
synthesis unit (coupled with ASU and 30 days of ammonia storage) in 
2030 would have up to 1.5% impact on the production cost of RE-based 
ammonia, as illustrated in Fig. 14. On the other hand, baseload opera-
tion of the ammonia plant could increase the feedstock supply cost, and 
consequently the ammonia production cost. As shown in Fig. 14, the cost 
of ammonia from a baseload ammonia plant could be up to 50% higher 
than the semi-flexible plant. The impact on the cost is less than 20% in 
regions with stable solar power supply or sites with access to cheap 
Fig. 12. Impact of decreasing WACC to 5% (left) and increasing WACC to 9% in respect to ammonia production cost by a WACC of 7% in 2030. 
Fig. 13. Impact of PV capex (top), Wind capex (centre) and battery capex (bottom) on levelised cost of ammonia Onsite in 2030. 
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geological hydrogen storage; but could be up to 40% at low-cost sites 
with a high share of wind in the mix of power supply, such as Patagonia. 
Thus, a potentially more expensive semi-flexible ammonia unit is well 
justified. 
The sensitivity of the Onsite ammonia cost in 2030 to the capex of 
major hydrogen facilities (electrolyser and compressor), with un-
changed opex fixed, is illustrated in Fig. 15. Since the model includes 
three different types of hydrogen storage, their capex difference already 
represents a sensitivity analysis and thus is not repeated here with the 
10% capex change. A 10% change in the capex of electrolyser results in 
about 1% and 2% change in the cost of RE-based ammonia in wind and 
PV-dominated regions, respectively. The higher impact of electrolyser 
capex on PV-dominated systems is because of higher installed capacities 
of electrolysers due to lower FLh of electricity supply by PV in com-
parison to wind turbines. This also indicates that, due to cost develop-
ment of electrolysers by 2030, electrolyser capex has a lower impact 
than capex of electricity supply on ammonia production cost, as shown 
for three sample nodes in Fig. S18. The impact of a 10% change in the 
capex of compressors is almost negligible. 
Fig. 14. Impact of ammonia plant (excluding electrolyser) capex on levelised cost of ammonia Onsite in 2030. 
Fig. 15. Impact of electrolyser capex (top) and hydrogen compressor capex (bottom) on levelised cost of ammonia Onsite in 2030.M. Fasihi et al. 
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3.4. Fossil vs. RE-based ammonia 
3.4.1. NG-based ammonia 
The main difference between conventional and RE-based ammonia is 
in the source of electricity and hydrogen supply. Apart from China, the 
global hydrogen supply to ammonia plants is mainly from NG via steam 
methane reforming (SMR). According to EC [2], NG demand for the Best 
Available Technology and Best Practiced Technology was about 28 and 
32 GJLHV/tNH3, respectively. Such NG-based ammonia plants also 
generate the required electricity from by-product steam via integrated 
steam turbines. Since EC [2] refers to documents from 1990s, it is 
assumed that the stated Best Available Technology has become the Best 
Practiced Technology by now. Thus, assuming total NG consumption of 
28 GJ/tNH3 (LHV), NG-based ammonia would have direct CO2 emissions 
of 1.57 tCO2/tNH3, excluding indirect CO2 equivalent emissions (global 
warming potential) of NG leakage in the extraction, transportation and 
process chain. In addition, the average CO2 emissions of the available 
plants is higher which has not been considered. 
To compare the cost of NG-based ammonia and green ammonia, it is 
assumed that the ammonia synthesis unit remains the same and only the 
electrolyser units and hybrid PV-wind power plants are substituted with 
SMR units and steam turbines (Fig. 16) to supply the same amount of 
hydrogen and electricity required for RE-based ammonia plants. In 
addition, the NG-based ammonia plant would not include the additional 
power and hydrogen balancing units as it runs on baseload. The required 
capacities of SMR unit and steam turbine are calculated based on their 
respective efficiencies which, together with financial specifications 
provided in Appendix A, would contribute to 302 €/tNH3⋅a, additional 
capex for a large-scale NG-based ammonia plant. Thus, the overall capex 
of the NG-based ammonia would be 931 €/tNH3⋅a, including 631 
€/tNH3⋅a for the ammonia synthesis unit. 
The cost of NG-based ammonia is a function of NG price and 
respective CO2 emissions cost. The cost of NG-based ammonia for a NG 
price range of 1 to 17 USD/MMBtu (2.6 to 44.6 €/MWhLHV) and CO2 
emission costs of 28, 61, 75 and 150 €/tCO2 projected for the years 2020, 
2030, 2040 and 2050 [51,52] are shown in Fig. 17. The fossil-based 
ammonia production cost is compared with the cost of green ammonia 
at best sites with a cumulative annual ammonia production potential of 
10 GtNH3, globally. 
The average price of NG has historically been between 40 and 100% 
of the crude oil price depending on the country or region [36]. However, 
it could be expected that the price of NG in ammonia exporting regions 
would potentially be in the lower half of this range. Thus, on the top 
horizontal axis of Fig. 17, the approximate crude oil price at each NG 
price level are provided based on a NG to crude oil price ratio of 50% 
with an expected ±20% divergence range. 
As illustrated in Fig. 17, the cost range of green ammonia at the best 
sites with 10 GtNH3/a cumulative generation potential are about 
440–630, 345–420, 300–330 and 260–290 €/tNH3 in 2020, 2030, 2040 
and 2050, respectively. In 2020, green ammonia is competitive with NG- 
based ammonia for a NG price of more than 15 USD/MMBtu (equal to a 
crude oil price of 174 USD/bbl), which would decrease to about 13 USD/ 
MMBtu (~150 USD/bblcrude oil) if 28 €/tCO2 GHG emissions costs are 
applied. In 2030, the cost competitiveness can be reached for a NG price 
range of 10.3–14.1 USD/MMBtu (~120–164 USD/bblcrude oil) without 
any CO2 emission cost, or a NG price range of 5.7–9.3 USD/MMBtu 
(~66–108 USD/bbl) for 61 €/tCO2 GHG emissions cost. In 2040 and 
2050, RE-based ammonia is competitive with fossil-based ammonia at 
NG prices over 8.2 and 6.3 USD/MMBtu (~95 and 73 USD/bblcrude oil), 
respectively. For 75 €/tCO2 GHG emissions cost, fuel parity in 2040 and 
2050 can be even reached for NG prices as low as 2.4 and 1 USD/MMBtu 
(~28 and 12 USD/bblcrude oil), respectively. Such GHG emission costs 
Steam 
Methane 
Reformer
ASU (N2 capture), 
feed gases 
compressors and 
NH3 synthesis unit
H2
Steam 
Turbine
el.
CO2
Water Baseload
NH3 supply
NG
Fig. 16. NG-based ammonia production chain. 
17
44.6
12 35 58 81 104 128 151 174 197
16
32
48
64
80
96
112
128
0
100
200
300
400
500
600
700
1 3 5 7 9 11 13 15
approximate crude oil price ±20% (USD/bbl)
A
m
m
on
ia
 co
st
 (€
/M
W
h H
H
V)
A
m
m
on
ia
 co
st
 (€
/t
N
H
3)
NG-based ammonia vs. green ammonia at best sites with 10 GtNH3/a cumul capacity
green ammonia 2020 green ammonia 2030
green ammonia 2040 green ammonia 2050
NG-based ammonia NG-based ammonia + 28 €/tCO2
NG-based ammonia + 61 €/tCO2 NG-based ammonia + 75 €/tCO2
NG-based ammonia + 150 €/tCO2
2.6 7.9 13.1 18.4 23.6 28.9 34.1 39.4
USD/MBtu NG
€/MWh NG
Fig. 17. NG-based vs. green ammonia cost for varying natural gas prices. 
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are at the same level as carbon capture and permanent storage from pure 
point sources [36]. Thus, beyond 2030 green ammonia could be cheaper 
than NG-based ammonia with carbon capture and storage or with 
realistic GHG emissions cost. These results indicate a steep demand 
growth for green ammonia latest by 2030s and the potential for 
substituting NG-based ammonia by 2040s globally. If ammonia is not 
supplied locally, the additional transportation costs of ammonia from 
different sources should be compared as well. 
The by-products of the RE-based ammonia production chain could 
increase its competitiveness with fossil-based ammonia. Frattini et al. 
[21] identified the waste heat sources eligible for recovery from a Haber- 
Bosch unit at 250 bar and 550 ◦C composed by the ammonia reactor 
(888 kWh/tNH3 at 550 ◦C) and the compressors cooling system (241 
kWh/tNH3 at 150 ◦C), equivalent to about 22% of the lower heating 
value of the produced ammonia. In addition, depending on the elec-
trolyser efficiency, the electrolysers supplying hydrogen to an ammonia 
plant would also generate about 1250–2200 kWhth of utilisable low- 
grade heat (about 80 ◦C) and 1.6 ton of oxygen per ton of ammonia. 
These by-products could potentially provide additional value through 
regional circular economy opportunities, such as district heating or as 
main energy input to low temperature CO2 direct air capture systems 
[53,54] and further increase the competitiveness of green ammonia with 
fossil-based ammonia. 
3.4.2. Coal-based ammonia 
The required energy for the best coal-based ammonia technology is 
about 48 GJLHV/tNH3 or 1.7 times the energy demand of NG-based 
ammonia [2], which is about 10% lower than the upper limit defined 
by China’s recent regulations for new coal-based ammonia plants [55]. 
Assuming bituminous coal with a heating value of 30.5 MJ/kg and a 
carbon emission factor of 25.8 tC/TJ [56], coal-based ammonia would 
have direct CO2 emissions of 4.5 tCO2/tNH3, excluding other hazardous 
emissions. Thus, the CO2 emissions and respective GHG emissions cost of 
coal-based ammonia are 2.9 times of NG-based ammonia. 
The investment cost of coal-based ammonia is reported to be 2.4 
times [4], 2.5 times [57], 2–3 times [2] or more than twice [58] as high 
as NG-based ammonia. In this study, a 2.4 times capex ratio (equal to 
2235 €/tNH3⋅a) is assumed for new coal-based ammonia plants, in the 
light of recent tighter environmental regulations. 
The cost of coal-based ammonia is a function of coal price andrespective CO2 emissions cost. China’s Qinhuangdao coal import spot 
price has been historically following the global crude oil market prices 
[59]. However, since China’s coal demand is mainly domestically sup-
plied [60], its coal price may follow a different pattern. Nevertheless, 
due to lack of information, it is assumed that domestic coal prices in 
China are comparable to the Qinhuangdao coal spot price. For a NG to 
OECD crude oil price ratio of 50%, the 2000–2017 average price ratio of 
coal to NG would be 46% based on the energy content. Considering 70% 
higher energy demand of coal-based ammonia, the cost of feedstock for 
coal-based ammonia would be still 78% of the feedstock cost of NG- 
based ammonia. 
At a natural gas price of 5 USD/MMBtu (13.1 €/MWhth), a constant 
coal to NG price ratio of 46% (67 USD/tcoal) and a WACC of 7%, the cost 
of coal-based ammonia would be 400 €/tNH3, which is relatively higher 
than the estimated cost of 380–410 USD/t (320–340 €/t) for coal-based 
ammonia in China [61]. This could be partly because of lower domestic 
coal prices in China and the relatively higher capex assumption for new 
plants, due to environmental regulations. If the capex ratio of coal-based 
ammonia to NG-based ammonia plants was set at 2, the production cost 
of ammonia would had been 54 €/tNH3 cheaper. Nevertheless, the cost 
difference of coal-based and NG-based ammonia is significantly bigger 
than potential ammonia shipping cost of about 20–40 €/tNH3, as 
explained in Section 3.5. Under such conditions, a shift to NG-based 
ammonia production or NG-based ammonia import may be expected. 
However, several factors slow down such potential changes. NG has a 
small share in China’s energy system and due to severe air pollution in 
China’s major cities, NG is primarily used for the power and heat sector. 
In 2012, China published new regulations for investments in the 
ammonia industry which bans the use of NG and high-quality anthracite 
coal in new ammonia plants [62]. It also puts certain limits for the en-
ergy consumption of existing and new ammonia plants and bans any 
plant with train capacity below 365,000 tNH3/a [55,62]. As a result of 
the new regulations and market economics, about 6 MtNH3/a capacity 
(about 10% of China’s demand) has been closed in 2017–2018, to be 
mainly replaced with new coal-based ammonia plants [61]. Meanwhile, 
China’s ammonia import was expected to only grow to 1 MtNH3 in 2019, 
yet three times more than the 2016 level [63]. The planning of new coal- 
based ammonia plants and limited import increase could be related to a 
limited distribution network for imported ammonia, as well as security 
of ammonia supply as a vital element to China’s growing food demand. 
However, Onsite Power-to-Ammonia in China has a great potential 
beyond its demands (Fig. 18) which could be cost-competitive with new 
coal-based ammonia plants at the best solar and wind sites beyond 2030. 
As illustrated in Figs. 18 and 19, in 2020, the green ammonia pro-
duction cost at the best sites in China with 1000 Mt annual ammonia 
production capacity would be in the range of 550–660 €/tNH3, equiva-
lent to coal-based production cost at coal prices over 200 USD/tcoal 
(equivalent to crude oil prices over 170 USD/bbl). However, if a 28 
€/tCO2 GHG emissions cost be applied, the cost of coal-based ammonia 
increases by 126 €/tNH3 and consequently the fuel parity would decrease 
to crude coal prices of 85–180 €/tcoal (~75–175 USD/bbl). For some 
Chinese electrolyser manufacturers, it is reported to have a capex of 200 
USD/kWel, significantly lower than from the leading Western manu-
facturers [64]. In an optimistic scenario, assuming a system-level capex 
half of the value in global scenario for low-cost Chinese electrolysers 
(~342.5 €/kWH2,HHV or 300 USD/kWel) for the same efficiency and 
durability as internationally leading manufacturers, the cost of RE-based 
ammonia could decrease by 100–200 €/tNH3 to 480–550 €/tNH3 in least- 
cost regions in 2020 (Fig. 18). However, even if such assumptions could 
be realised, RE-based ammonia would be more expensive than coal- 
based ammonia cost of 320–340 €/t in China [61]. By 2030, enforcing 
even small CO2 emissions cost as low as 20 €/tCO2 on the fossil-based 
ammonia industry in China by policy-makers would significantly in-
crease the cost of coal-based ammonia by 90 €/tCO2 and would make 
green ammonia competitive with current coal-based ammonia cost of 
320–340 €/t. The monetisation of the by-product heat from RE-based 
ammonia plants could be the other option to close the gap. By 2040, 
green ammonia would be fully cost competitive with coal-based 
ammonia at large scale in many regions even without consideration of 
any GHG emissions cost. Thus, at no additional cost, a shift to green 
ammonia would decrease China’s coal consumption and respective GHG 
emissions, while maintaining security of supply. In addition, if inte-
grated with the power sector, flexible ammonia plants, electrolysers and 
hydrogen storage can provide additional flexibility to a power sector 
with high shares of solar and wind electricity, which would be a great 
added value of green ammonia plants to China’s energy system. More-
over, domestic green ammonia could be partly decoupled from the 
location of power supply via power lines. This would provide the pos-
sibility of installation of new ammonia plants at brown fields or close to 
ammonia consumption sites, which could further decline the cost of the 
ammonia value chain. Since China has very good solar and wind re-
sources, the stated special circumstances could make China a global 
leader in green ammonia production. Once implemented at a scale, the 
cost of modular NH3 synthesis units and electrolysers, as major con-
tributors to the total cost, would significantly decline, which would 
further decline the cost of green ammonia globally and would also pave 
the path for a faster replacement of NG-based ammonia with green 
ammonia. 
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Fig. 18. Industrial cost curves for Power-to-Ammonia in China, based on cost-optimised hybrid PV-wind power plants for the period 2020 to 2050 (left) and levelised 
cost of Onsite green ammonia in 2030 (right, top) and 2050 (right, bottom). 
Fig. 19. Coal-based vs. green ammonia cost for varying coal prices. 
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3.5. Ammonia shipping and trading options 
As shown in Figs. 4 and 6, the capacity and regional distribution of 
least-cost sites in 2020 and 2030 is limited, which encourage construction 
of large-scale ammonia plants at the least-cost sites. Such plants benefit 
from a relatively lower capex as well, as explained in Section 2.1. The low- 
cost RE-based ammonia can then be transported to the consumption sites 
by ship, pipeline, rail or truck [65]. Ammonia is usually shipped in LPG 
carriers in liquid state at –33 ◦C and ambient pressure [66]. For a chosen 
vessel, the levelised cost of shipping is a function of annually transported 
ammonia which mainly depends on the shipping distance and speed as 
formulated in Eq. (8) and illustrated in Fig. 20. A generic fuel consump-
tion of 0.0082 kWhth/DWT-km is considered for deep sea vessels ac-
cording to Horvath et al. [67]. DWT stands for deadweight tonnage that 
the vessel can carry, of which 90% is considered to be the cargo weight 
[68]. The impact of fuel type on the ship capex and available space for 
cargo is negligible, according to Horvath et al. [67].In a conservative 
approach, the same fuel consumption level is assumed for the empty 
vessel on its return trip. At 13,500 km, Patagonia to the Netherlands is a 
relatively long international shipping route, which in return would have a 
shipping cost of about 43–59 €/tNH3 for a shipping fuel price of 20–80 
€/MWhth. The 20 €/MWhth case represents low-cost diesel (at ~40 USD/ 
bblcrude oil), the 40 €/MWhth case represents high-cost diesel (at ~80 
USD/bblcrude oil) or low-cost diesel with 75 €/ton GHG emissions cost or 
low-cost RE-based ammonia as a shipping fuel in 2050, while the 80 
€/MWhth case represents RE-based ammonia as a shipping fuel in 2020. A 
combination of high-cost diesel and significant GHG emissions cost is 
unlikely as the demand for fossil fuels and consequently their price is 
expected to decline when significant GHG emission costs are applied. The 
shipping cost is independent from the cost of cargo ammonia, assuming 
no ammonia is lost in the shipping process. The chosen vessel for this 
analysis was a mid-size LPG carrier. The use of larger ships can potentially 
reduce the shipping cost by economies of scale. 
China (33.7%) and Europe (21.5%) had the highest ammonia con-
sumption in the world in 2016, followed by South Asian Association for 
Regional Cooperation (SAARC) (over 11.4%), North America (11.4%), 
Middle East (8.3%) and Africa (3.5%) [69]. Fig. 21 illustrates the po-
tential of ammonia production in 9 major regions. Among the major 
ammonia consumers Europe, India, Middle East and Africa have Onsite 
ammonia production cost of about 570–700 €/tNH3 in 2020, while a 
decade-average price (2007–2017) of ammonia in Belgium (as a Euro-
pean country) and India has been about 300–350 €/tNH3 (Supplementary 
Data, Fig. S1). A 28 €/t GHG emissions cost in 2020 would add about 44 
€/tNH3 to the cost of conventional ammonia, which is still not enough to 
close the gap with the least cost sites. Nevertheless, a more realistic 
WACC of 4% for the power sector in Europe could lower the cost of 
electricity supply for ammonia production. On the other hand, land use 
conflict and competition with power sector in utilisation of electricity 
from the best sites (mainly in Iceland, UK and coastal areas of Western 
Europe) could limit Europe’s capacity for ammonia generation, yet 
enough for introduction of RE-based ammonia at commercial scale to 
the European market. Such internal trade could also avoid relatively 
higher shipping costs from other continents to Europe. By 2030, least- 
cost regions are slightly above average market prices and could secure 
market parity if some level of CO2 emissions cost would be applied, or a 
lower level of WACC would be possible or there would be some benefit 
from by-product heat. Thus, by 2040 RE-based ammonia reaches market 
parity with fossil-based ammonia in more regions. Beyond 2040, low- 
cost RE-based ammonia would be accessible globally and the differ-
ence of ammonia production cost at Onsite least-cost regions and world’s 
Coastal least-cost would decrease to less than 40 €/tNH3, comparable to 
the shipping cost for routes of about 10,000 km. Such cost distribution 
could limit intercontinental ammonia shipping to shorter routes such as 
Morocco-Europe, as discussed for the case of synthetic fuels by Fasihi 
et al. [70], and Australia-Japan, as discussed for the case of RE-based 
liquefied natural gas by Gulagi et al. [71]. It would also encourage the 
implementation of mid-scale local ammonia plants, which in contrary, 
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fuel cost at 20 €/MWhth fuel cost at 40 €/MWhth
fuel cost at 80 €/MWhth specific cost at 20 €/MWhth
specific cost at 40 €/MWhth specific cost at 80 €/MWhth
Fig. 20. Ammonia shipping cost by distance. 
Levelised cost of shipping =
ship capital cost∙
(
crf + opexfix
)
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2∙distance
ship average speed
+ unload & upload time
+
fuelcons.∙distance∙2∙fuelprice
cargo share of DWT
(8) 
M. Fasihi et al. 
Applied Energy xxx (xxxx) xxx
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have a higher capex. Since ammonia energy demand is mainly in the 
form of hydrogen provided by flexible water electrolysers, integration 
with the local grid connection could also add additional flexibility to the 
overall local energy system and reduce the costs. On the other hand, 
liquid synthetic fuels such as diesel and kerosene are ideal for 
intercontinental transportation due to their higher calorific density, 
large scale plants for export, minimum shipping cost and available 
infrastructure [49]. Nevertheless, ammonia trading between Australia 
and Japan could still be a long-term option due land limitation in Japan, 
low-cost ammonia production in Australia (combination of good solar 
Fig. 21. Industrial cost curves for ammonia Onsite (left) and Coastal (right) in the 9 major regions, based on cost-optimised hybrid PV-wind power plants for the 
period 2020 to 2050. 
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resources and low local WACC) and relatively lower sea distance be-
tween the two countries. Recent research by Osman et al. [72] also 
concludes that fossil fuel exporters in the Middle East could become 
green ammonia exporters in the future. 
4. Conclusion 
In this study, cost-optimised configuration of Onsite and Coastal 
Power-to-Ammonia plants based on hourly power supply from hybrid 
PV-wind power plants and balancing technologies is modelled. The 
model evaluates the least-cost ammonia production cost and capacity in 
a 0.45◦ × 0.45◦ spatial resolution based on efficiency and cost pro-
jections for the years 2020, 2030, 2040 and 2050. 
The results show that up to 10 billion tons of Onsite RE-based 
ammonia can be generated annually at the best sites in the world for a 
cost range of 440–630, 345–420, 300–330 and 260–290 €/tNH3 in 2020, 
2030, 2040 and 2050, respectively and for a WACC of 7%. For such 
generation costs, green ammonia production could be cost-competitive 
in niche markets by 2030 and in higher volumes beyond 2030 with 
drop in the cost of renewables and balancing technologies. Best sites for 
ammonia production in 2020 could have rather excellent solar and wind 
resources such as Patagonia and Atacama Desert or a low WACC for 
investment such as Northwest European countries. Applying a GHG 
emissions cost could significantly change the time and scale of such cost- 
competitiveness. For GHG emissions costs of 75 €/tCO2, RE-based 
ammonia in 2040 would be cost-competitive with natural gas at prices 
as low as 2 USD/MMBtu. Thus, countries that apply GHG emission costs 
or restriction on fossil fuels will become the first markets for green 
ammonia until it becomes fully cost-competitive by 2040 regardless of 
the applied GHG emission cost. 
Beyond 2040, the cost difference of least-cost Onsite ammonia pro-
duction at major regions is not more than the additional cost of Coastal 
ammonia production and shipping cost which consequently could limit 
intercontinental ammonia trading to regions with area limitation for 
local green ammonia production. 
The coal-based ammonia supply in China is a unique case. It is more 
expensive than NG-based ammonia due to a capex intensive process and 
would be more affected by a potentialGHG emissions cost in the future due 
to 2.9 times emissions per ton of ammonia. Moreover, fuel cost has a smaller 
share in the total cost of coal-based ammonia. Thus, unlike NG-based 
ammonia, coal-based ammonia cannot benefit much from lower coal pri-
ces to survive in a tightening market by higher GHG emissions costs or 
cheaper green ammonia. The locally produced green ammonia in China is 
expected to be cost-competitive with coal-based ammonia in 2030 for a 
modest GHG emissions cost of 10–30 €/tCO2 and fully cost competitive in 
2040 and beyond without any GHG emissions cost consideration. Low 
natural gas resources, very good solar and wind resources, coal-based 
pollution, as well as importance of locally produced ammonia (energy se-
curity, grid flexibility and by-product heat) could make China a leading 
country for the advancement of green ammonia in the world. 
Results show that in an islanded setup, PV is the dominating tech-
nology by 2030 in most parts of the world except for Patagonia and far 
northern regions, due to the excellent wind resource availability. In 
addition, gas turbines are not expected to have a significant role in the 
cost-optimised system and batteries are mainly installed for balancing 
the direct electricity requirement of the ammonia plant rather than 
increasing the utilisation rate of electrolysers. Such a system design 
mainly relies on flexibility of electrolysers and availability of semi- 
flexible synthesis units or low-cost hydrogen caverns. 
Future research is needed on the cost of ammonia transportation via 
pipelines in different terrain conditions in comparison to electricity 
transmission lines. In addition, high spatial resolution maps of suitable 
sites for PV and wind power plants installation are required in order to 
differentiate between theoretical and technical potential of green 
ammonia. 
CRediT authorship contribution statement 
Mahdi Fasihi: Conceptualization, Data curation, Resources, Soft-
ware, Validation, Visualization, Writing - original draft, Writing - review 
& editing. Robert Weiss: Data curation. Jouni Savolainen: Data 
curation. Christian Breyer: Conceptualization, Supervision, Writing - 
review & editing, Funding acquisition. 
Declaration of Competing Interest 
The authors declare that they have no known competing financial 
interests or personal relationships that could have appeared to influence 
the work reported in this paper. 
Acknowledgements 
The authors gratefully acknowledge the financial support of LUT 
University and the public funding of Business Finland for the ‘P2XEN-
ABLE’ project under the number 8588/31/2019, which partly funded 
this research. The first author thanks the Gasum Gas Fund for the 
valuable scholarship. We also thank Ashish Gulagi for proofreading. 
Appendix A 
See Table A1. 
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Table A1 
Technical and financial specifications. 
Device Unit 2020 2030 2040 2050 Ref. 
PV fixed tilted capex €/kWp 580 390 300 246 [25] 
€/kWp 432 278 207 166 [26] 
€/kWp 475 306 207 166 this study 
opex fix €/(kWp⋅a) 13.2 10.6 8.8 7.4 [25] 
€/(kWp⋅a) 7.76 5.66 4.47 3.70 [26] 
€/(kWp⋅a) 8.53 6.23 4.47 3.70 this study 
lifetime year 30 35 40 40 [51] 
PV single-axis tracking capex €/kWp 638 429 330 271 [25,73] 
€/kWp 475 306 228 183 [26,73] 
€/kWp 523 337 228 183 this study 
opex fix €/(kWp⋅a) 15 12 10 8 [25,73] 
€/(kWp⋅a) 8.54 6.23 4.92 4.07 [26,73] 
€/(kWp⋅a) 9.40 6.86 4.92 4.07 this study 
lifetime year 30 35 40 40 
Wind energy (onshore) capex €/kWp 1150 1000 940 900 [51,74] 
opex fix % of capex p.a. 2 2 2 2 
lifetime year 25 25 25 25 
wake effect % 7 7 7 7 
Battery storage capex €/kWh 234 110 76 61 [26] 
opex fix €/(kWh⋅a) 3.28 2.20 1.90 1.71 
opex var €/kWh 0.0002 0.0002 0.0002 0.0002 
lifetime year 20 20 20 20 [74] 
cycle eff. % 91 93 95 95 [75] 
self-discharge %/h 0 0 0 0 
Battery interface capex €/kW 117 55 37 30 [26] 
opex fix €/(kW⋅a) 1.64 1.1 0.93 0.84 
opex var €/kWh 0 0 0 0 
lifetime year 20 20 20 20 [74] 
Combined cycle gas turbine capex (conventional) €/kW 775 775 775 775 [76] 
capex (H2-fuelld) €/kW 853 853 853 853 10% higher capex 
opex fix % of capex p.a. 2.5 2.5 2.5 2.5 [76] 
opex var €/kWh 0.002 0.002 0.002 0.002 [76] 
lifetime year 35 35 35 35 [77] 
eff. (LHV) % – 58 60 60 [76,78] 
eff. (HHV) % – 52.2 54 54 
Open cycle gas turbine capex (conventional) €/kW 475 475 475 475 [76] 
capex (H2-fuelld) €/kW 523 523 523 523 10% higher capex 
opex fix % of capex p.a. 3 3 3 3 [76] 
opex var €/kWh 0.011 0.011 0.011 0.011 [76] 
lifetime year 35 35 35 35 [77] 
eff. (LHV) % – 43 44 45 
eff. (HHV) % – 38.7 39.6 40.5 [76] 
HVDC (underground cable) capex €/(kW⋅km) 1.2333 1 1.2333 1 1.3667 2 1.3667 2 [79] 
opex fix % of capex p.a. 0.1 0.1 0.1 0.1 [79] 
lifetime year 50 50 50 50 [80] 
efficiency % per 1000 km 96.4 1 96.4 1 98.4 2 98.4 2 [79] 
HVDC (overhead line) capex €/(kW⋅km) 0.20 1 0.20 1 0.30 2 0.30 2 [79] 
opex fix % of capex p.a. 1 1 1 1 [79] 
lifetime year 50 50 50 50 [80] 
efficiency % per 1000 km 93.4 1 93.4 1 98.4 2 98.4 2 [79] 
HVDC (Blended) capex €/(kW⋅km) 0.303 0.303 0.407 0.407 this study: 
opex fix €/(kW⋅km⋅a) 0.0019 0.0019 0.0028 0.0028 10% underground 
lifetime year 50 50 50 50 90% overhead 
efficiency % per 1000 km 93.7 93.7 98.4 98.4 
HVAC (overhead line) capex €/(kW⋅km) 0.244 0.244 0.244 0.244 [79] 
opex fix % of capex p.a. 1 1 1 1 [79] 
lifetime year 50 50 50 50 [80] 
efficiency % per 1000 km 86 86 86 86 [79] 
Converter station capex €/kW 150 1 150 1 180 2 180 2 [79] 
opex fix % of capex p.a. 1 1 1 1 
lifetime year 50 50 50 50 
efficiency % 98.6 98.6 98.6 98.6 
(continued on next page) 
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Table A1 (continued ) 
Device Unit 2020 2030 2040 2050 Ref. 
Alkaline water electrolyser capex €/kWH2,HHV 685 380 296 248 [36,81,82] 
(30 bar outlet) opex fix % of capex p.a. 3.5 3.5 3.5 3.5 
opex var €/kWhH2 0.0036 0.0018 0.0013 0.0010 
lifetime year 30 30 30 30 
eff. (HHV) % 73.3 76.2 79.2 82.1 
H2 compressor capex (6 MWH2) €/kWH2,LHV 100 100 100 100 [38] 
capex (150 MWH2) €/kWH2,HHV 29 29 29 29 this study4 
opex fix % of capex p.a. 4 4 4 4 [38] 
lifetime year 20 20 20 20 
pressure range bar 30–200 30–200 30–200 30–200 [39] 
el. consumption kWhel/kWhH2,HHV 0.040 3 0.040 3 0.04 3 0.040 3 [38,39] 
Salt cavern H2 storage capex €/MWhH2,HHV 386 374 370 367 [83] 
(~4000 tH2, net) opex fix % of capex p.a. 4 4 4 4 [39] 
opex var €/kWhH2 0.0002 0.0002 0.0002 0.0002 
lifetime year 30 30 30 30 [39] 
cycle eff. % 100 100 100 100 
max charge/discharge %/day 8 8 8 8 [40] 
pressure range bar 60–200 60–200 60–200 60–200 [39] 
Lined rock cavern H2 storage capex €/MWhH2,HHV 1120 1120 1120 1120 [83] 
(~500 tH2, net) opex fix % of capex p.a. 4 4 4 4 
opex var €/kWhH2 0.0001 0.0001 0.0001 0.0001 
lifetime year 30 30 30 30 
cycle eff. % 100 100 100 100 
max charge/discharge %/day 8 8 8 8 
pressure range bar 20–200 20–200 20–200 20–200 
Underground pipeline H2 
storage 
capex €/MWhH2,HHV 10,860 10,860 10,860 10,860 based on [83] 
(~800 tH2, net) opex fix % of capex p.a. 2 2 2 2 
opex var €/kWhH2 0.0001 0.0001 0.0001 0.0001 
lifetime year 30 30 30 30 
cycle eff. % 100 100 100 100 
max charge/discharge %/h 16.7 16.7 16.7 16.7 
pressure range bar 20–200 20–200 20–200 20–200 
Ammonia Synthesis Unit 5 capex (400 kt/a) €/tNH3.a 631 631 631 631 based