Decarbonisation potential of
synthetic kerosene

Final Report

E4tech (UK) Ltd for
Ministerie van Infrastructuur en Waterstaat
May 2021

Contents
1

Executive Summary ................................................................................................................................... 1

2

Introduction ............................................................................................................................................... 8

3

4

5

2.1

Background ....................................................................................................................................................... 8

2.2

Objectives of study ............................................................................................................................................ 8

2.3

Scope and approach to the study...................................................................................................................... 9

Definition of routes and modelling approach ......................................................................................... 11
3.1

Definition of routes ......................................................................................................................................... 11

3.2

Model definition .............................................................................................................................................. 21

Results and analysis ................................................................................................................................. 25
4.1

Techno-economic modelling ........................................................................................................................... 25

4.2

Capacity ramp-up and feedstock modelling .................................................................................................... 42

Conclusions and implications .................................................................................................................. 64

Appendix A

: Methodology for assessment of synthetic kerosene production potential .......................... 68

Appendix B

: Techno-economic modelling ................................................................................................. 78

Appendix C

: Descriptions of Water Gas Shift (WGS) and Reverse Water Gas Shift (RWGS) ..................... 87

E4tech (UK) Ltd

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London SW1H 0HW
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Company no. 4142898

Tel: +44 20 3008 6140
Fax: +44 20 3008 6180

Registered address:
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www.e4tech.com

Decarbonisation potential of synthetic kerosene

1 Executive Summary
Reducing emissions from aviation is an important policy aim for the Netherlands
The need to tackle climate change will require deep emissions reduction which is likely to affect all
sectors of the economy, including air travel. This is an area of concern for the Netherlands, since
international aviation is an important sector of the economy, as evidenced by higher than average
share of aviation fuel in overall fuel consumption compared with other EU Member States. As a
result, there is government interest in exploring innovative solutions to address the climate impacts
of international aviation. In 2020, a Sustainable Aviation Agreement was adopted at the Sustainable
Aviation Roundtable, which committed the Dutch government to a target of at least 14% of the
aviation fuel bunkered in the Netherlands in 2030 being sustainable.
This study assesses the potential for synthetic kerosene to contribute to aviation decarbonisation
A range of options are available to produce lower carbon substitutes to fossil jet kerosene. Biofuel
based on hydroprocessed esters and fatty acids (HEFA) is currently the most developed option, and
while several other biofuel options have been certified for use, routes other than HEFA are either at
the first-of-a-kind commercial, demonstration or earlier stages. In addition to bio-based routes,
synthetic kerosene can be made from hydrogen produced from renewable electricity combined with
CO and/or CO2 from a range of sources. Non-renewable synthetic kerosene could also be produced
using hydrogen from fossil sources, particularly natural gas with carbon capture and storage, and
similar carbon sources.
The future potential of synthetic kerosene will be dependent on its cost competitiveness and ability
to deliver significant GHG savings. Understanding the energy, GHG emissions and cost of synthetic
kerosene production is therefore crucial to informing policy-making in this area. The processes
required to convert hydrogen and carbon sources into synthetic kerosene, such as Fischer-Tropsch
synthesis, benefit from large-scale implementation. How quickly production can be scaled up will
partly determine the speed with which cost reductions can be achieved, making scalability and
resource availability, including renewable electricity, critical to the competitiveness of synthetic
kerosene routes.
The study has three principal objectives:
•
•
•

Establish and compare the resource use (including energy), GHG emissions and production costs
of different synthetic kerosene production routes;
Examine, in the context of resource availability and competition for resources, the potential GHG
savings that can be delivered and the abatement costs; and
Evaluate the potential scale-up and availability of synthetic kerosene and business case that
would underpin its commercialisation.

The scope of the study was to present the evidence relevant to these objectives in order to inform
the policy debate, but the study specifically excludes any discussion of the policy implications of the
evidence and findings. In line with this approach, the price of CO2 has been ignored throughout this
study both in terms of the cost of producing synthetic fuels from fossil sources and the effect on the

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Decarbonisation potential of synthetic kerosene
price of fossil kerosene. However, the GHG abatement costs calculated in this study provide an
indicator of the level at which the carbon price would need to be set in order for synthetic kerosene
to achieve cost parity with conventional fossil kerosene. In addition, the report does not assess
where globally synthetic kerosene could be most cost-effectively produced or from which countries
the most likely sources of supply would emerge.
Several routes have been modelled
This study models a range of synthetic kerosene routes including those using hydrogen from “green”
(renewable power) and “blue” (abated natural gas) sources, along with CO2 captured from biogenic
and fossil point-sources or CO2 from direct air capture (DAC). It also separately considers routes
which use waste fossil CO from steel mills as an input, and these routes are referred to as recycled
carbon fuels, not blue. Biogenic CO routes and routes involving hydrogen from biomethane have not
been considered as part of this study. The routes are illustrated in the graphic below.

Figure 1: Production routes considered

A number of important conclusions have been drawn from the analysis carried out and these are set
out in the following section:
Current costs are high for green routes, whereas blue routes offer a lower cost alternative today
The analysis shows that estimated costs of green synthetic jet fuel today would likely be very high,
ranging from €4,300 – 6,800/tonne compared with pre-COVID fossil jet prices of around €600/tonne
(assuming no carbon price is applied to fossil fuels). Costs for the methanol and FT routes are very
similar, since the majority of the production cost is hydrogen, and both routes have similar hydrogen
requirements. However, FT routes are ASTM approved and are more commercially mature than
methanol to jet routes, which are yet to be ASTM certified.
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Decarbonisation potential of synthetic kerosene
Blue routes (where blue hydrogen is combined with CO2) currently have a cost advantage over green
routes, due to the lower cost hydrogen, but the cost of blue synthetic kerosene at €1,500 –
2,300/tonne is still significantly higher than the price of fossil jet. Note that routes using waste CO
could be more competitive, as discussed below.
The most costly routes are those involving DAC, which is still to be commercialised, and requires
significant energy inputs (which could be renewable, or supplied from power and gas grids). It is
anticipated that the cost of DAC will fall considerably over time, reflecting learning rates,
industrialisation of production and economies of scale. A faster ramp-up could accelerate these cost
reductions.
Improving efficiencies and falling renewable power generation prices will see the cost of green and
blue routes converge by 2050
While blue synthetic kerosene is shown to be cheaper than green today, a combination of factors will
lead costs to converge over time. In 2050, the cost of green routes is in the ranges €1,500 –
2,000/tonne while blue routes are in the range €1,300 – 1,700/tonne. The biggest factor is the
expected fall in renewable electricity costs, although improving electrolyser efficiencies and falling
capital costs across the process chain as scales increase also play a role. However, rising natural gas
costs also contribute to the convergence in costs, by limiting blue route cost reductions. This
convergence could facilitate a transition from blue to green routes over time, especially as the
imposition of any carbon price on fossil fuels would tend to reduce the competitiveness of blue
routes relative to green.
However, even after cost reductions, in 2050 the cost of synthetic kerosene remains significantly
above the price of fossil jet today, implying that there would need to be continued support for
synthetic kerosene routes, or a carbon price on fossil fuels (assuming fossil jet prices were not to rise
significantly over time).

Within each route, the
columns are for 2020, 2030
and 2050 data moving left
to right

Figure 2: Production costs for CO 2 + FT synthetic kerosene routes by year

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Decarbonisation potential of synthetic kerosene

The GHG savings from blue routes are modest
While synthetic kerosene produced from blue hydrogen + CO2 is likely to be less costly than fuel
produced from green hydrogen + CO2 today, it delivers only limited GHG savings. If synthetic
kerosene based on blue hydrogen + CO2 is deemed to have acceptable GHG savings and is adopted as
an interim solution, it will be important to consider how this can transition from blue to green
hydrogen over time in order to achieve Net Zero targets. Alternatively, blue hydrogen + CO2 routes
could be deemed to have insufficient GHG savings, and so might not be supported in policy.
Synthetic kerosene from blue hydrogen + CO2 from DAC may actually lead to an increase in GHG
emissions compared to fossil jet depending on the assumptions made about the source of heat
energy for the DAC process (in this analysis, assumed to be high temperature DAC fuelled by natural
gas). Emissions from blue hydrogen + CO2 routes are in the range 50-113 gCO2e/MJLHV today falling to
49-81 gCO2e/MJLHV in 2050 (for comparison the REDII transport fossil fuel benchmark is 94
gCO2e/MJLHV), with the routes employing biogenic point source CO2 being the most attractive. This
compares with 1-22 gCO2e/MJLHV for the green hydrogen + CO2 routes, although it is important to
note the differences in underlying assumptions for DAC heating used in the blue and green routes. It
should however be noted that biogenic point sources of CO2 are likely to have limited availability and
it is expected that the availability of fossil point sources of CO2 will also decline over time due to
policy.
Within each route, the columns
are for 2020, 2030 and 2050
data moving left to right

Figure 3: Lifecycle GHG emissions by FT route and year

GHG abatement costs are high initially but come into line with biofuel SAF routes over time
Both the green and blue synthetic kerosene routes have high GHG abatement costs today, reflecting
the high costs of the green routes and the relatively poorer GHG performance of the blue routes.
GHG abatement costs today are in the range €900 – 1,500/tCO2e for green routes and €500 –

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Decarbonisation potential of synthetic kerosene
900/tCO2e for blue (see Figure 26), but by 2050, green routes are expected to have lower abatement
costs than blue routes, given falling costs. The CO based routes can have lower GHG abatement costs
than the CO2 routes, but only if the counterfactual1 use of the feedstock is unabated.
By 2050, synthetic kerosene is expected to have GHG abatement costs in a similar range to SAF from
other routes such as advanced biofuel routes (see Figure 43).
Routes which utilise CO rather than CO2 could provide a relatively low cost option and GHG
emissions savings for sites where waste CO is available and unabated
The use of recycled waste fossil (or biogenic) CO in the production of synthetic kerosene via FischerTropsch is relatively attractive as the reverse water gas shift reaction required for CO2 routes can be
avoided. Fuel costs of around €1,000 – 1,300/tonne in 2030 could be achievable from fossil CO with
associated emissions highly dependent on the feedstock counterfactual used. For example, for the
CO + WGS route in 2030, synthetic kerosene net lifecycle GHG emissions of -137 gCO2e/MJLHV (i.e. a
very large GHG saving) could be achieved if the feedstock counterfactual is unabated power
generation (see Figure 24), but emissions would be 75 gCO2e/MJLHV if the counterfactual is abated
power generation (see Figure 25). The equivalent figures for CO + blue H2 are 27 gCO2e/MJLHV and 96
gCO2e/MJLHV, and for the CO fermentation + ATJ route they are 32 gCO2e/MJLHV and 190 gCO2e/MJLHV
respectively in 2030 (see Figures 22 and 23).
While there are a number of large point sources of fossil CO available from industrial processes
today, these may not be as geographically dispersed as CO2 sources, potentially limiting the locations
where this technology could be used. Fossil CO volumes are not limited today, but could be expected
to reduce in availability over time as processes such as steel production decarbonise (e.g. switching
from coking coal to technologies such as direct reduced iron). Since the FT process is indifferent to
the source of syngas, CO based plants could transition from fossil CO to biogenic CO or from blue to
green hydrogen, or with some further investment, transition to use of CO2 (although this has not
been analysed in this study).
Methanol based routes show similar cost and GHG performance to FT alternatives
A full set of methanol to jet routes was explored using either green or blue hydrogen and the complete
range of CO2 sources. The cost and GHG performance of these routes was almost identical to the
results obtained for the FT routes. We conclude that any preference for one approach over the other
would be driven by operational considerations rather than cost or carbon reduction potential. For
example, methanol can be used as a fuel directly, as an input to other fuels including synthetic
kerosene and as an intermediate input to products such as plastics; this market flexibility may be
considered an advantage by some producers and may allow economies of scale to be realised.

1 A “counterfactual” is defined as an alternative use for fossil feedstocks, e.g. CO from steel mills would otherwise be used for unabated or

abated power generation if it were not used to produce synthetic kerosene, and so displaced emissions (e.g. from reduced power export to
the grid) should also be accounted for in the synthetic kerosene GHG emissions. This counterfactual differs from the RED II fossil
“benchmark” value of 94gCO2e/MJLHV against which a fuel’s lifecycle GHG emission savings are calculated.

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Decarbonisation potential of synthetic kerosene

Figure 4: Production costs for CO-based synthetic kerosene routes (top chart: LanzaTech route 13 and
bottom chart: CO + FT routes 14-15 in the year 2030 only)

Capacity scale-up could be rapid and make a contribution to the Netherlands’ SAF objectives
The capacity build up modelling carried out for this study suggests that supply could reach 966
ktonnes/year in Europe by 2030, and 28 Million tonnes/year by 2050 if the majority of global activity
were to remain in Europe. At global scale, synthetic kerosene deployment could reach 1.3 Million
tonnes/year in 2030 and 36.7 Million tonnes/year by 2050. Synthetic kerosene routes could therefore
materially contribute to overall SAF supplies.
A review of feedstock availability suggests that based on this capacity build up, feedstock potentials
are unlikely to restrict the rate at which capacity of any of the routes considered can be rolled out.
However, specific local constraints (e.g. on carbon sequestration or supply of renewable electricity)
could affect the speed of roll out.
Whilst transitions or energy system modelling have not been examined in this study, an approach to
developing synthetic kerosene that allows the use of both green and blue routes could potentially
accelerate scaling up of the whole synthetic kerosene industry, with blue shifting to green hydrogen
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Decarbonisation potential of synthetic kerosene
supplies over time – although blue routes may have to meet certain GHG savings thresholds to be
deemed acceptable.
Blue hydrogen production at scale would be consistent with the optimal scale for fuel synthesis, but
is dependent on CCS infrastructure, and fossil infrastructure lock-in risks and continued emissions
need careful consideration. Green routes, while currently significantly more expensive, have very low
emissions, do not necessarily rely on CCS infrastructure, will benefit from rapidly decreasing
renewable power costs, and could contribute to balancing increasing renewable power on the grid.
Recycled fossil CO sources could be utilised for jet fuel production in the near to mid-term, but the
need to avoid fossil emissions means that steel mills and other industries will increasingly
decarbonise towards 2050, limiting the availability of these routes, and requiring switching of the jet
synthesis plant to other feedstocks (either biogenic CO, green H2 and/or non-fossil CO2 sources).
30

Green MtJ (routes (4-6)

Green FT (routes 1-3)

CO to Jet (routes 13-15)

TOTAL

Jet fuel [ Mtonnes / year ]

25

20

15

10

5

Figure 5: Route breakdown of synthetic kerosene in Europe to 2050 under the fast growth scenario

Further possible areas of investigation include a more detailed analysis of Net Zero compatible
pathways and assessment of alternative electrolysis routes
A valuable area of further investigation would be around Net Zero compatible transition pathways,
and how quickly the sector will have to transition from the use of point fossil sources of CO2 and/or
blue hydrogen to routes that use DAC or biogenic CO2 in conjunction with green hydrogen. This should
include consideration of the relative merits of different routes, including both FT and methanol
options. A more structured pathway analysis including timeframes, phase out/phase in transitions and
total cumulative GHG savings would be useful in developing a roadmap for the development of
synthetic kerosene.
A number of additional technologies are under development or consideration which have not been
considered in this analysis, e.g. high temperature solid oxide electrolysis and CO2 co-electrolysis, and
these could be explored in more detail. Some of these technologies offer promise, e.g. in terms of
improved efficiency, so support for their research and development could help them to achieve
commercial readiness more quickly.
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Decarbonisation potential of synthetic kerosene

2 Introduction
2.1 Background
Lower carbon, sustainable aviation fuels (SAF) are expected to play an important role in reducing
aviation GHG emissions, and international and national policies are being developed to reduce
aviation GHG emissions from the aviation sector. This includes the Netherlands’ draft Civil Aviation
Policy Memorandum 2020-2050 which aims to set GHG emissions reduction targets and to mandate
the use of renewable fuel by 2023, if no mandate is set at EU level.
The aviation industry will continue to be heavily reliant on energy-dense kerosene fuels. Today SAF is
seen as the most promising solution to decarbonise the aviation sector. Alternative technologies are
either not suited to service medium-long haul flights (e.g. electrification) or are still a long time away
from realisation and commercial deployment (e.g. hydrogen). Significant capacity ramp up of SAF fuels
will be needed to achieve the climate targets of the aviation industry.
A range of options are available to produce low carbon substitutes to fossil jet kerosene. Biofuel
based on hydro-processed esters and fatty acids (HEFA) is currently the most developed option,
although long-term feedstock supplies are likely limited. While several other biofuel options have
been certified for use, routes other than HEFA are either at the first-of-a-kind commercial,
demonstration or earlier stages.
In addition to bio-based routes, synthetic kerosene can be made from hydrogen produced from
renewable electricity combined with CO and/or CO2 from a range of sources e.g. fossil, biogenic or
atmospheric (synthetic kerosene). Non-renewable synthetic kerosene could also be produced using
hydrogen from fossil sources, particularly natural gas with carbon capture and storage, and similar
carbon sources. These synthetic routes are less developed than the bio-based SAF routes, but
interest in their potential has been growing, linked to the interest in renewable and low carbon
hydrogen, and it is these routes that will be the focus of this report.
In addition to technical feasibility, other factors such as regulatory, logistical and commercial aspects
affect the large-scale deployment of synthetic kerosene fuels, and the future potential of synthetic
kerosene will be dependent on its cost competitiveness and ability to deliver significant GHG savings.
Understanding the energy, GHG emissions and cost of synthetic kerosene production, the rate at which
its production could be scaled up and the resources required is therefore crucial in informing policymaking in this area.

2.2 Objectives of study
The overall aim of this study is to evaluate the energy, emissions and economic performance of
synthetic kerosene production, and to analyse its scalability. The specific objectives of the study are
to:
•
•
•

Establish and compare the resource use, including energy, GHG emissions and production costs
of different synthetic kerosene production routes;
Assess the potential GHG savings that can be delivered and the abatement costs; and
Evaluate the potential for scale-up and availability of synthetic kerosene, taking into
consideration resource availability, and the requirements for commercialisation.

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Decarbonisation potential of synthetic kerosene
In addressing these objectives, a picture will be developed of how the use of synthetic kerosene
could help the Netherlands achieve its 2030 SAF target, and how synthetic kerosene could support
the achievement of any SAF mandate envisaged by the EU.

2.3 Scope and approach to the study
To realise the objectives set out in Section 2.2, this study was conducted in two parts. The first part
focused on techno-economic and emissions modelling, while the second part considered resource
availability and capacity ramp-ups:
•

•

Task 1 estimated the energy and feedstock requirements, GHG emissions and costs of synthetic
kerosene production and discusses the implications in terms of emissions savings, abatement
cost and business cases.
Task 2 assessed the sustainable scale-up potential and availability of synthetic kerosene in the
short term (2030) with an outlook for the longer term (2050), taking into account potential
resource availability constraints.

The production routes considered in this study are set out in Table 1 grouped according to the key
synthesis process.
Table 1: Description of routes and processes considered in this study

Source of
carbon
Source
of H2
“Green” hydrogen
from renewable
electrolysis

“Blue” hydrogen
from natural gas
reforming with
CCS

Fossil CO2

1. RWGS + FT
synthesis to jet

2. RWGS + FT
synthesis to jet

3. RWGS + FT
synthesis to jet

4. Methanol
synthesis +
methanol to jet

5. Methanol
synthesis +
methanol to jet

6. Methanol
synthesis +
methanol to jet

7. RWGS + FT
synthesis to jet

8. RWGS + FT
synthesis to jet

10. Methanol
synthesis to
methanol to jet

11. Methanol
synthesis to
methanol to jet

Water

Fossil CO

Direct Air Capture
(DAC)

Biogenic CO2

15. FT synthesis to
jet

9. RWGS + FT
synthesis to jet
12. Methanol
synthesis +
methanol to jet

13. CO
fermentation to
ethanol to jet
14. CO WGS + FT
synthesis to jet

Other routes such as biogenic CO routes, or biomethane reforming, have not been considered within
the scope of this study, but could be studied in future work. Figure 6 illustrates the production routes
from Table 1 in graphical form. The routes are discussed in more detail in Section 3.

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Decarbonisation potential of synthetic kerosene

Figure 6: Production routes considered

It should be noted that a number of additional technologies are under development or consideration
which have not been considered in this analysis. Notably, earlier stage technologies such as high
temperature solid oxide electrolysis or CO2 co-electrolysis have been excluded from the study. Some
of these technologies offer promise, e.g. in terms of improved efficiency, so support for their research
and development could help them to achieve commercial readiness more quickly.
Each of the routes has different considerations in terms of resource availability, sustainability and
scale-up potential, which needed to be analysed as outlined below:
•

•

•

Current status of routes. What is the current status of the selected synthetic kerosene routes and
what are the high level challenges to scale-up and deployment? What current and planned projects
are in the pipeline and what is their production capacity? Which players are active in the industry?
Short and long term outlook. What are the expectations in terms of capacity scale-up in the short
and long-term based on bottom-up scenarios to 2030, and extrapolation using growth rates to
2050?
Resource availability considerations. What are the feedstock requirements for the routes, how
quickly can these be scaled up to underpin the capacity development and what competition might
exist between these resources, especially renewable electricity for green routes or CCS
infrastructure for natural gas routes? Note that when considering the resource implications, these
routes are grouped into four principal classes of technology which share common feedstocks.

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Decarbonisation potential of synthetic kerosene

3 Definition of routes and modelling approach
3.1 Definition of routes
3.1.1 Renewable electrolysis + Fischer-Tropsch (Routes 1-3)
Routes 1, 2 and 3 involve renewable electrolysis to produce hydrogen which is then combined with
CO2 in a reverse water-gas-shift (RWGS) reaction to produce the syngas needed for FT synthesis.
Green hydrogen can be produced from renewable electricity via electrolysis of water. Low
temperatures systems either use a Polymer Electrolyte Membrane (PEMEL) or alkaline (AEL)
electrolyser. PEMEL is commonly considered as it has fast start-up times and better part load
performance than AEL which makes it more suited for use with intermittent renewables. However,
PEMEL capital costs are higher than for AEL, and AEL technology is much more established. An
alternative could be high temperature Solid Oxide Electrolyser (SOE), given its higher electrical
efficiency due to the use of input heat. SOE may have lower capital costs than PEMEL, but SOE costs
and lifetimes/degradation profiles are more uncertain given their lower level of maturity.
A variety of CO2 sources can be used, such as, biogenic point sources (biomass power plants, biogas
upgrading, fermentation to alcohols), fossil point sources i.e. industry/power sector emissions (gas
power/CHP plant emissions, cement and steel plant emissions), or Direct Air Capture (DAC) from the
atmosphere. Point sources of CO2 vary in their purity and pressure, but typically can be captured at
relatively low cost with the input of some heat and power. By comparison, DAC plants involve greater
capital outlay and high inputs of heat and/or power, and are a significantly higher cost CO2 source
given the scarcity of CO2 in the atmosphere. These CO2 sources are common across all the different
routes.
CO2 is converted to CO using some of the renewable H2 in the RWGS reaction and combined with
further renewable H2 to produce syngas (H2 and CO) which is the input required for FT synthesis.
RWGS reaction: CO2 + H2 → CO + H2O
FT synthesis produces syn-crude, a broad mix of hydrocarbons containing light gas (C1-C4), naphtha,
middle distillates, light waxes and heavy waxes.
FT general reaction: CO + 2H2 → -(CH2)- + H2O
This is followed by a distillation step where the gases, water and FT liquids produced from the FT
reactor are separated. Hydrogen can then be used to catalytically reduce the size of large
hydrocarbons (waxes) into more useful, narrower carbon number range fractions (hydrocracking).

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Decarbonisation potential of synthetic kerosene

Figure 7: Value chain for renewable electrolysis + RWGS + FT synthesis from CO 2

As an alternative to the RWGS reaction, electrolysis can also be used to convert CO2 to CO. A PEM
electrolyser or solid oxide electrolyser can be used. CO2 electrolysis technology are at around TRL 6-7
as Haldor Topsøe has a demonstration SOEC unit2 and Opus 12 has developed some demonstration
PEM units.
CO2 electrolysis: 2 CO2→2 CO+O2
Alternatively, a solid oxide electrolyser operating in co-electrolysis mode could be used to enable the
simultaneous splitting of H2O and CO2. However, this is still at an earlier development stage at around
TRL 5. Sunfire are the main actor looking to develop PtL projects using co-electrolysis technology.
Co-electrolysis: H2O(steam) + CO2 → H2 + CO + O2.
The electrochemical reduction of CO2 to CO (via electrolysis or co-electrolysis) is less commercialised
than RWGS, and has therefore not been considered in this study’s cost, GHG emissions and energy
efficiency analysis. However, these alternative technologies could have potential in terms of reducing
system complexity and costs, and could be explored further in future work.

Technology and Commercial Readiness
The combined electrolysis, RWGS and FT process is currently at TRL 5-6, with its use in pilot and
demonstration plants, although scales are ramping up with some large projects announced. The
readiness of the RWGS process depends upon scale: small scale RWGS is at TRL 7, while large scale
RWGS processes are at TRL 5-6, as scaling up is difficult due to the risk of coke formation in larger
plants. FT synthesis of syngas and hydrocracking are widely established processes and are at TRL 9.
From a commercial standpoint, electrolysis + RWGS + FT synthesis is proven at demonstration scale,
and projects are planned at commercial scale (TRL 7), but current production costs are high3. This is
mainly due to electricity costs, electrolyser CAPEX, and the fact that downscaling FT equipment to
match electrolyser sizes negatively affects the capital cost per unit of fuel produced. Electrolyser
plants are expected to reach gigawatt scale over time, by connecting multiple electrolyser modules
together, tending to reduce or eliminate this optimal fuel synthesis scale mismatch.
2 Haldor Topsoe (2017) Small-scale CO from CO2 using electrolysis

https://www.topsoe.com/hubfs/2115834/CAMPAIGNS/eCOs/Haldor%20Topsoe%20India%20article.pdf
3 Brynolf, Selma, et al. "Electrofuels for the transport sector: A review of production costs." Renewable and Sustainable Energy Reviews 81
(2018): 1887-1905. https://www.sciencedirect.com/science/article/abs/pii/S1364032117309358

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Decarbonisation potential of synthetic kerosene
Table 2: Summary of renewable electrolysis + FT synthesis from CO 2 plants
Project

Location

Electrolyser

Sunfire/Audi
PtL plant

Dresden,
Germany

Sunfire
(SOEL 10kWe)

Soletair
Pilot Plant

Lappeenranta,
Finland

N/A
(PEM 5kWe)

ICO2CHEM

Frankfurt,
Germany

N/A
(Chlor-alkali, kWe
scale)

Technical
University
of Hamburg
(GP2J)

Stade,
Germany

N/A

Copenhagen
Airports,
Maersk,
DSV
Panalpina,
DFDS, SAS,
Ørsted
Zenid

Copenhagen,
Denmark

FT Synthesis

Scale
(thousand
litres/yr)
3.7

Products

Timeline

e-Gasoline
e-Diesel
e-jet

INERATEC
(RWGS)
VTT (FT
MOBSU)
INERATEC
(RWGS, FT
Synthesis)
VTT (FT Cobased)
N/A

0.7

e-Gasoline

1.5

Chemicals
(white oils and
high weight
waxes)

Started
operation in
2014, now
concluded
Started
operation in
2017, now
concluded
Planned to start
in 2020

N/A

e-jet
e-Diesel

Stage 1: 10 MWe
Stage 2: 250 MWe
Stage 3: 1300
MWe

N/A

Stage 1:
2,400
Stage 2:
48,00
Stage 3:
312,000

Methanol; Jet,
Road and
Marine diesel

Rotterdam,
The
Netherlands

Sunfire,
Climeworks (DAC)

INERATEC

320 –
1,280

e-jet

Norsk e-Fuel

Herøya,
Norway

Sunfire (coelectrolysis),
Climeworks (DAC)

Nordic
electrofuel
(was Nordic
Blue Crude)
Kopernikus
Project
(Phase 2)

Herøya,
Norway

TBC (Alkaline
electrolyser)

TBC

10,000
(by 2023),
100,000
(by 2026)
10,000

KIT, Karlsruhe,
Germany

Sunfire (coelectrolysis),
Climeworks (DAC)

INERATEC

73

FT waxes to be
refined to eGasoline, eDiesel, e-jet
FT waxes to be
refined to eGasoline, eDiesel, e-jet
e-Gasoline
e-Diesel
e-jet

Construction
scheduled from
2022. Plan
announced in
April 2019
Each stage
could be
operational by:
Stage 1: 2023
Stage 2: 2027
Stage 3: 2030
2023
construction
proposed.
Currently in
review of FEED
phase.
Planned
commissioning
in 2023
FEED study
underway

Plans for 2022
start announced
in April 2019

3.1.2 Renewable electrolysis + Methanol to jet (Routes 4-6)
Methanol can be produced from CO2 sources in either one or two catalytic steps. The conventional
route for methanol production involves a two-step process in which the RWGS reaction is first used
to convert CO2 to CO in the RWGS reaction, which is then combined with H2 to make syngas, and
reacted to form methanol. However, more recently direct synthesis routes are being explored which
involve the direct reaction of hydrogen with CO2 to produce methanol and water, requiring different
reactor designs. Technology developer Carbon Recycling International (CRI) is pursuing this route,
given the potential for enhanced methanol selectivity and reduced energy consumption.

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Decarbonisation potential of synthetic kerosene
Methanol can then be upgraded into longer chain chemicals and fuels, for example via a process
optimised for the production of molecules in the jet fuel range. Methanol-to-Jet synthesis first uses
the Methanol-to-Olefins (MtO) process. The produced olefins (e.g. ethylene and propylene) are then
oligomerised to form straight chain paraffinic hydrocarbons, which are subsequently fractionated.
Depending on the selectivity of the oligomerisation step, hydrogenation and/or isomerisation may be
needed prior to distillation to meet jet product specifications.
The route via methanol has the advantage over FT in that intermediate storage of liquid methanol is
simple, low cost and safe (compared to gaseous syngas or hydrogen storage). This also creates a
buffer between variable renewable power inputs, and the downstream methanol refining process
which operates best at continuous loads. Methanol also offers the possibility to develop the
synthetic fuel project in phases, by first setting up synthetic methanol supply chains (e.g. as a
sustainable fuel for shipping) and in a second phase extending the project to the production of
synthetic kerosene.

Figure 8: Value chains for Renewable electrolysis + Methanol + Methanol to jet route

Technology and Commercial Readiness
Although methanol production from syngas is commercially available (TRL 7-9) and has been for
some time, methanol production through catalytic synthesis of hydrogen and CO2 is at TRL 7, with a
number of large-scale projects in the planning stages. The largest existing plant is the 5ML/year
Carbon Recycling International plant in Svartsengi, Iceland, which uses dedicated geothermal
electricity and CO2 recovered from the geothermal power station as feedstocks.
Production costs are heavily influenced by electricity costs and remain high compared to other
methanol production routes such as biomass/coal gasification or fossil gas reforming and catalysis4.
The few operational projects are situated near renewable power plants in order to secure low-cost
electricity and avoid grid fees, and are paired with carbon capture from point sources.

4 IRENA, 2019; Hydrogen: A Renewable Energy Perspective. https://www.irena.org/-

/media/Files/IRENA/Agency/Publication/2019/Sep/IRENA_Hydrogen_2019.pdf

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Decarbonisation potential of synthetic kerosene
Table 3: Summary of CO 2 catalysis to methanol projects
Project

Location

Electrolyser

Methanol
synthesis

Scale
(million
litres/yr)
139

Timeline

Patagonia
Feasibility Study

Chile,
Patagonia

Siemens
(200Mwe)

N/A

Copenhagen
Airports, Maersk,
DSV Panalpina,
DFDS, SAS, Ørsted

Denmark,
Copenhagen

Stage 1: 10 Mwe
Stage 2: 250 Mwe
Stage 3: 1300
Mwe

N/A

Stage 1:
2.4
Stage 2:
48
Stage 3:
312
5

Each stage could be
operational by:
Stage 1: 2023
Stage 2: 2027
Stage 3: 2030

George Olah
plant

Iceland,
Svartsengi

N/A
(6 Mwe alkaline)

MefCO2 project –
Mitsubishi Hitachi
Power Systems
Europe
FreSMe project –
Carbon Recycling
International

Germany,
Niederaußem

Hydrogenics
(1 Mwe PEME)

Carbon
Recycling
International
Carbon
Recycling
International

0.46

Operational since 2019

Sweden,
Luleå

E2Fuel project –
MAN Energy
Solutions
Power2Met –
GreenHydrogen

Germany,
Haßfurt

None
(CRI’s ETL process
uses by-product
hydrogen)
Siemens
(1.25 MWe PEME)

Carbon
Recycling
International

0.014

Construction completed end
of 2019, now in
commissioning phase

MAN Energy
Solutions

Tbd

Project started in 2018. Plant
start-up planned for 2021

Denmark,
North Jutland

GreenHydrogen
(10-30 MWe)

Re::Integrate

10

Project started in 2019. Plant
start-up planned for 2021

Westküste 100
project

Germany,
Heide

Thyssenkrupp (30
Mwe planned to
2030)

Heide
Refinery

-

30 MWe (electrolyser)

Me2Go project –
Swiss Liquid
Future (former
Silicon Fire)
Nouryon-led
consortium
Mider-Helm
Refinery
Liquid Wind –
FlagshipONE
INOVYN

Switzerland

Thyssenkrupp
(5 MWe)

Silicon Fire

5

Planned. Implementation
agreement signed in 2018 to
build 5 plants

Netherlands,
Delfzijl
Germany,
Leuna
Sweden

McPhy
(20 MWe alkaline)
Sunfire
(1 MWe)
Nel
(alkaline)
(NA)

BioMCN

N/A

Announced January 2020

Total/Helm
AG
Haldor
Topsoe
INOVYN

0.21

Production start-up in 2021

55

Announced, planned to start
production in 2023
Announced 2020

Belgium,
Antwerp

N/A

Operational since 2012

planned to 2025, scaling up to
700 MWe by 2030

10

Although there is limited publicly available information on the methanol-to-jet route, this is likely to
be based on commercially available technologies which will have to be adapted to this specific
process. The MTO process has already been developed by a small group of technology developers
(UOP, DICP, Sinopec and Lurgi)5. Both the UOP MTO and the Lurgi MTP processes have been used by
several plants in China using coal-based methanol. In the second step, olefins are oligomerised to
form straight chain paraffinic hydrocarbons, which are subsequently fractionated. This step would be

5 Gogate, 2019, “Methanol-to-olefins process technology: current status and future prospects”,

https://www.tandfonline.com/doi/full/10.1080/10916466.2018.1555589#:~:text=The%20reactor%20and%20process%20conditions,0.3MP
a)%20and%20is%20exothermic.

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Decarbonisation potential of synthetic kerosene
similar to an oligomerisation process licensed by Sud-Chemie or PetroSA, known as Conversion of
Olefins to Diesel and Gasoline (COD)6.
Although the individual steps for this process are commercially available, no single licensor currently
offers a complete end-to-end package, and it is unclear at what scale the integrated process has
been tested: therefore the methanol-to-jet chain is estimated to be at TRL 4-5. Also, while the
production of synthetic jet fuels through Fischer-Tropsch synthesis is certified under ASTM D7566,
the methanol to jet route is not yet certified, and certification could take several years.
Currently only one consortium has been established with the objective to develop and demonstrate a
methanol to jet pilot scale process, under the KEROSyn100 project7. This project is part of a portfolio
of projects called “I100” aimed at developing a Power-To-X demonstration hub in the Heide region in
Germany. KEROSyn100 brings together partners from industry and academia and received federal
funding of €4.2 million. The developer claims that the process can be more selective towards jet than
FT-processes. No details are given on the process configuration or catalysts, but these are likely to be
analogous to those described previously. The current work on the KEROSyn100 pilot project suggests
strong interest for an ASTM certification for the Methanol to Jet (MtJ) route.

3.1.3 Natural gas reforming + Fischer-Tropsch (Routes 7-9)
Routes 7, 8 and 9 involve steam methane reforming (SMR) with CCS to produce hydrogen, then the
addition of external CO2 supplies before a reverse water-gas-shift (RWGS) reaction to syngas,
followed by FT synthesis. These routes involve taking carbon out of the methane feedstock, before
adding carbon back in from an external source, so only make sense if transport of hydrogen and
external CO2 to the FT site is significantly more efficient and cheaper than transport of the external
CO2 to the SMR sequestration site. Otherwise, a cheaper and more efficient overall solution would be
fossil gas to liquid (GTL) jet fuel production, along with sequestration of the point source or direct air
capture CO2. It is for this reason that the external CO2 supply cannot come from other SMR plants, as
this is effectively an inefficient fossil GTL process with high GHG emissions.
Steam Methane Reforming (SMR) is the principal hydrogen production method worldwide and
involves the catalytic reaction of fossil natural gas with steam followed by a water-gas shift reaction
to produce hydrogen and CO2. The heat required is supplied externally, typically by burning natural
gas/process streams onsite. The CO2 from the reformer (around 60% of the input carbon) is at
relatively high purity and pressure, and can be captured and sequestered at low cost. Process
configurations in this study assume that the CO2 from flue gases onsite are also captured at higher
cost, raising total SMR plant CO2 capture rates to around 90%. Note that the CO2 needed for jet fuel
synthesis is provided from another external source (typically a dilute CO2 point source or via DAC).
Partial oxidation (POX) is an alternative non-catalytic process, in which the feedstock is gasified in
the presence of oxygen before a water-gas shift reaction to produce hydrogen and CO28. While the
operation of a POX reactor is less expensive than SMR, due to heat being produced instead of being
required, the hydrogen yields are lower, making this route more expensive. POX is considered to be a
6 Halmenschlager, Cibele Melo, et al. "Oligomerization of Fischer–Tropsch tail gas over H-ZSM-5." Industrial & Engineering Chemistry

Research 55.51 (2016): 13020-13031.
7 KEROSyn100 project, 2018, https://www.heiderefinery.com/en/press/press-detail/kerosyn100-taking-to-the-skies-with-green-fuel/
8 Kalamaras, C., M., Efstathiou, A., M., 2013. Hydrogen Production Technologies: Current State and Future Developments. Available online
at: https://www.hindawi.com/journals/cpis/2013/690627/

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Decarbonisation potential of synthetic kerosene
well-established TRL-9 hydrogen production method that can deliver a >99% CO2 capture rate with
pure oxygen used instead of air.9
Autothermal reforming (ATR) is a combination of both steam reforming (endothermic) and partial
oxidation (exothermic) reactions8. In ATR, steam is added in a catalytic partial oxidation process8. ATR
has the advantages of not requiring external heat and being simpler and less expensive than SMR, as
well as having higher CO2 capture rates8. Another advantage of ATR over SMR is that it can be shut
down and started rapidly, while producing a larger amount of hydrogen than POX alone8. However,
ATR plants typically need to be much larger than SMR plants for economic viability.
For the analysis, we focused on SMR as it is the largest route to hydrogen production in the EU in the
present day. Other than the source of hydrogen, these routes are identical to those detailed in
Section 3.1.1., in terms of the RWGS reaction, FT synthesis, distillation, and hydrocracking.

Figure 9: Value chain for SMR with CCS + RWGS + FT synthesis from CO

Technology and Commercial Readiness
SMR is at TRL 9, while CCS is currently at TRL 7-8 given a number of large demonstration and several
first-of-a-kind commercial projects involving capture, pipeline and geological sequestration (although
with a heavy focus on enhanced oil recovery). SMR+CCS is considered to be at TRL 7-8 given that Air
Products has a CCS plant in Port Arthur, Texas, which has been operating for several years10. The
whole route to jet fuel, i.e. SMR with CCS + RWGS + FT is currently only at TRL 4-5. There is no
evidence of developers currently considering the entire chain mentioned above. This overall route is
already certified under ASTM D1655, given the Fischer-Tropsch synthesis step.

3.1.4 Natural gas reforming + Methanol to jet (Routes 10-12)
The technology and processes involved in these value chains have already been described in sections
3.1.3 (reformation + CCS to produce hydrogen) and 3.1.2 (methanol synthesis and methanol to jet).
As discussed above, these routes involve taking carbon out of the methane feedstock, before adding
9 Technology developer Pers. Comm.
10 IEA GHG, 2018. The CCS project at Air Products’ Port Arthur hydrogen production facility. Available online at:

https://ieaghg.org/publications/technical-reports/reports-list/9-technical-reports/956-2018-05-the-ccs-project-at-air-products-port-arthurhydrogen-production-facility

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Decarbonisation potential of synthetic kerosene
carbon back in from an external source, so only make sense if transport of hydrogen and external
CO2 to the methanol site is significantly more efficient and cheaper than transport of the external
CO2 to the SMR sequestration site. Otherwise, a cheaper and more efficient overall solution would be
fossil gas to methanol production (then methanol to jet), along with sequestration of the point
source or direct air capture CO2. It is for this reason that the external CO2 supply cannot come from
other SMR plants, as this would effectively be an inefficient fossil process with high GHG emissions.

Figure 10: Value chains for SMR with CCS + Methanol + Methanol to jet route

At least three fossil methanol projects are currently operational hat apply carbon capture and
utilisation for enhanced fossil methanol production, but no projects currently involve methanol
production using a source of blue hydrogen produced with CCS. There are also no known or planned
projects including conversion of “blue methanol” into jet. Regarding technology readiness levels,
SMR is at TRL 9 while CCS is at TRL 7-8, methanol production via RWGS reaction to syngas is at TRL 79, and methanol to jet is at TRL 4-5.

3.1.5 Steel mill gas fermentation + ethanol to jet (Route 13)
The syngas fermentation route using fossil off-gases containing carbon monoxide (CO) from steel
mills has been pioneered by Lanzatech. In Lanzatech’s approach, the residual blast oxygen furnace
gas stream from the steel mill is cooled, cleaned and injected into a fermentation vessel containing
proprietary microbes and liquid media. The microbes grow by consuming the waste gases (typically
mostly CO is consumed, but they are also being developed to utilise CO2 and H2). Ethanol and other
chemicals are produced by these microbes and can be recovered from the fermentation broth.

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Decarbonisation potential of synthetic kerosene

Figure 11: Steel mill gas fermentation to ethanol to jet route

The fermentation of steel mill gases to ethanol is currently at TRL 7-8, with first commercial plants in
operation in China and under construction in Europe.
Table 4: Summary of steel mill gas fermentation to ethanol projects
Developer
Lanzatech +
Shougang Group
ArcelorMittal
(Steelanol EU
H2020 project)
Baowu Group,
Lanzatech,
Baosteel gases,
Sinopec, Virgin
Airline
Lanzatech– CSC China Steel
Cooperation
Lanzatech, Indian
Oil Company (IOC)
PNNL, Lanzatech,
Imperium, Boeing

Tech
licensor
Lanzatech

Lanzatech

Location
Hebei
province,
China
Ghent,
Belgium

Scale (million
litres/yr)
58

Feedstock

Products

Status

Steel mill gases

Ethanol

Operational since
2018

80

Blast furnace
offgas

Ethanol

Under
construction

Lanzatech

Shanghai,
China

0.45

Waste gas from
steel mill

Ethanol

Operational since
2017

Lanzatech

Kaohsiung,
Taiwan

127

Waste gas from
steel mill

Ethanol

Operational since
2015

Lanzatech

Panipat, India

40

Ethanol

Announced

Lanzatech

US

0.0111

Waste gas from
steel mill
Waste gas from
steel mill

Jet fuel

Operational since
2015

Alcohol to jet technology is not yet in commercial use, though is based on technologies well known in
the oil and gas industry. Short chain alcohols (ethanol, n-butanol, and isobutanol) are dehydrated to
ethene or butene, which are then processed through oligomerisation reactions, followed by
hydrogenation, isomerisation and finally distillation into the required product streams. Gasoline,
diesel and jet can be produced, with the exact output depending on the process configuration.
Currently operating at TRL 5, the alcohol to jet process could quickly reach a higher TRL given
decades of prior industrial experience with the component technologies. The alcohol to jet process
produces jet which has been ASTM approved for 50:50 blend with Jet-A.

11 This is based on the following: LanzaTech scaled up the ATJ process, producing 4000 gallons of jet and 600 gallons of diesel for testing

and a future proving flight (LanzaTech, n.d. A Hybrid Catalytic Route to Fuels from Biomass Syngas. Available online at:
https://www.osti.gov/servlets/purl/1423741). Unit conversions: 1 US Gallon kerosene = 3.8 litres (Aqua-calc: https://www.aquacalc.com/calculate/volume-to-weight)

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Decarbonisation potential of synthetic kerosene

3.1.6 Steel mill gas + Fischer-Tropsch (Routes 14 and 15)

Figure 12: Value chains for conversion of steel mill gases to jet fuel via FT

Two possible routes are envisaged to take steel mill gases (CO) and catalytically convert them via FT
to jet fuel (without the use of microbes). Steel mill gases typically contain a mix of CO, CO2 and
impurities. The small amount of CO2 is first removed and then the resulting gas stream is cleaned to
remove the impurities and produce high purity CO, as required for the downstream catalytic
processes.
In route 14, roughly two thirds of the CO is reacted with steam in a WGS reaction to produce H2 and
CO2 (CO + H2O → CO2 + H2). The high purity CO2 can then be captured at a very high capture rate and
sequestered. The H2 produced is combined with the remaining CO in a FT reactor to produce FT
products, which are treated to produce jet fuel. As detailed in Section 3.1.1, hydrocracking reactions
will be used to produce hydrocarbon chains with the specific chain lengths required for jet fuel.
In route 15, all the CO is combined with hydrogen from an external source in the FT reactor, avoiding
the WGS reaction and the generation of CO2 before FT synthesis.
At least one technology developer has commercial scale plans to use at least one of these two
routes. Other than CCS (used directly in route 14, or in route 15 due to the external blue hydrogen
production), each of the components are commercialised at TRL 9, although the overall system is
currently at a lower TRL (estimated to be at around TRL 5 today). Routes 14-15 could therefore be
rapidly built at commercial scale once CCS is available. The FT facility could also be modified to use
green hydrogen (instead of blue hydrogen) or biogenic CO feedstocks (if these were available nearby
or as steel mills switch from fossil CO to biogenic CO) later on which would help avoid lock-in or
stranded fossil assets.

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Decarbonisation potential of synthetic kerosene

3.2 Model definition
3.2.1 Techno-economic modelling
A techno-economic model was developed and used to assess the synthetic kerosene routes
presented in the previous section. The model provides estimates of overall energy efficiency, raw
material inputs, GHG emissions and levelised costs for synthetic kerosene production for each route.
The model structure is shown in Appendix B, which illustrates the input data, intermediate products,
synthesis steps and outputs. The routes are modelled with a modular approach in which unit
processes (e.g. PEM electrolysis, DAC CO2, RWGS, fuel synthesis) are combined to create each specific
route. Each module takes costs (e.g. equipment, utilities), mass balances and energy balances as
inputs. More detailed information can be found in Appendix B. A number of key assumptions were
made when developing the model, as set out below.

Hydrogen production routes
Renewable hydrogen production uses data for a PEM electrolyser with a stack lifetime of 62,000
hours, and assuming a 85% annual load factor (see assumptions on power mix below). Other
electrolysers (either alkaline or solid oxide) would have different CAPEX and efficiencies but a single
technology was selected to minimise the number of routes modelled. Assumptions for current and
future electrolyser capital costs, OPEX and energy efficiency were taken from an industry report12.
Blue hydrogen production uses data for an SMR plant with a 90% CO2 capture rate, and
representative upstream fossil gas supply emissions. Other reformation technology e.g. ATR or
ATR+GHR or Partial Oxidation would have different CAPEX, efficiencies and capture rates.
Sensitivity analysis allows the impact of alternative technology choices to be seen and the results of
these are detailed in Appendix B.

CO2 sources
Different sources for CO2 have been considered. Biogenic (Route 1 and Route 7) and fossil (Route 2
and Route 8) point sources of CO2 are assumed to arise from the combustion of forestry biomass
residues and fossil natural gas respectively in power plants. CO2 from both of these point sources is
assumed to be captured from exhaust gases of these power plants and delivered to the fuel synthesis
plant at a cost of €40/tCO2.13 The CAPEX and OPEX for point source CO2 capture and delivery are not
modelled explicitly, but the GHG emissions calculations have taken into account the added electricity
and heat requirements for CO2 capture at these power plants (requiring more of the feedstock to be
burnt). Note that no carbon tax has been applied in the analysis.
Five DAC options have been modelled based on high-temperature DAC data from Carbon
Engineering, each with a different source of heat and power. These options are presented in Table 5.

12 Hydrogen supply chain evidence base, Element Energy and Jacobs, Nov 2018, for the UK Department for Business, Energy & Industrial

Strategy
13 Brynolf et al., 2018, "Electrofuels for the transport sector: A review of production costs"

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Decarbonisation potential of synthetic kerosene
Table 5: Heat and power sources for different DAC options
DAC 1

DAC 2

DAC 3

DAC 4

DAC 5

Heat source

Natural gas

Green H2

Renewable
electricity

Blue H2

Blue H2

Electricity
source

Grid electricity

Renewable
electricity

Renewable
electricity

Grid electricity

Renewable
electricity

The DAC energy sources chosen impact both the cost and GHG emissions as shown in Figure 15 and
Figure 17. However, ‘base case’ scenarios for these DAC options were chosen to be paired with either
green or blue hydrogen feedstocks for comparison with CO2 from point sources, rather than present
five DAC choices in every chart. These were:
•
•

Natural gas for heat and grid electricity - this DAC 1 option (“Grid DAC” as in the Executive
Summary) has been paired with routes utilising blue hydrogen (Route 9a);
Green hydrogen for heat and renewable electricity - this DAC 2 (“Green DAC” as in the Executive
Summary) option has been paired with chains using green hydrogen (Route 3b);

Since Carbon Engineering data is only available for fully commercialised plants (estimated to be
achieved by 2050), scaling factors have been used to estimate 2020 and 2030 CAPEX and efficiencies.
Sensitivity analysis is performed to assess the impact of changing these uncertain input energy
requirements, which encompasses the range of input energy requirements seen by lowertemperature DAC systems as well.

FT liquids route
The RWGS reactor has a heating requirement and the FT plant has a minor electricity requirement
which are treated in the following way:
•
•
•

Natural gas for heat and grid electricity have been modelled as the inputs for routes utilising
blue hydrogen.
Green hydrogen for heat and renewable electricity have been modelled as the inputs for
chains using green hydrogen.
For the CO routes 13-15 grid electricity for power and natural gas for heat have been
modelled in this study, although it is possible that more renewable sources could be used in
the future which would affect both the cost and GHG emissions.

This is to ensure that the chains presented for comparison are ‘blue’ or ‘green’ throughout, from the
origin of the hydrogen feedstock, including the power and heat requirements for DAC, as well as the
power and heat requirements for the fuel synthesis processes.

Power mix
A blend of dedicated renewables such as solar and wind power may be able to achieve ~5,000
equivalent full load hours but the FT reactor and electrolysers will achieve the lowest fuel production
costs with ~7,500 full load hours or more. Therefore, even if there are dedicated renewables on site,
this renewable electricity generation will likely have to be supplemented with grid electricity. To
avoid the necessity of a direct renewables connection to the fuel synthesis plant with large battery
storage, and to buy renewables across the grid for these additional hours, some form of contractual
agreement (e.g. Power Purchase Agreement) and/or cancellation of guarantees of origin would likely
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Decarbonisation potential of synthetic kerosene
be required for the green hydrogen routes. This would need to be allowable under a policy
mechanism – however, the RED II rules on renewable power additionality and any spatial or temporal
correlation requirements are still being developed this year. For simplicity here, we have assumed
that the supply to the electrolyser is fully renewable. A sensitivity has been run on the cost and GHG
emissions impacts if different approach to power supplies is taken. However, by 2050, the NL grid is
assumed to be fully decarbonised14, so the emissions difference between the approaches will
disappear. Table 20 in Appendix B gives the key input assumptions.

GHG accounting
Regulation is still evolving with regards to synthetic fuels and a finalised GHG methodology for
renewable fuels of non-biological origin and recycled carbon fuels are not fully defined under RED II
yet, and only due to be finalised later in 2021. We have conducted our analysis on the latest
understanding of likely EU policy decisions.
From a GHG accounting perspective, transport fuel policies in the EU (REDII) and in the UK (RTFO) do
not include embodied emissions from the manufacturing, construction and decommissioning of
renewable power plants, hydrogen production facilities or fuel production facilities within GHG
emissions calculations. We have therefore not included these embodied emissions in our analysis.

3.2.2 Capacity ramp-up and feedstock modelling
The capacity ramp-up model is divided into two timeframes: the near term up to 2030 and the long
term between 2030 and 2050. The modelling approach differs between the two stages, reflecting the
degree of uncertainty that exists over the capacity build up.
In the short term, a ‘bottom-up’ approach is used, based on information on companies already active
in the industry at European and global scale. The approach taken reflects the technical ability of the
industry to scale-up, based on the current number of technology developers, scale of existing and
planned plants, and plausible build-rates in this industry. This relies on both a supportive policy
environment and technology developer success. This means that all companies currently working on
synthetic kerosene production are assumed to continue to do so, and are assumed to license their
technology once they get to a sufficient scale. Importantly, the framework of the model does not
consider competition between the individual conversion routes or between different sectors.
In the long term to 2050, a ‘top-down’ approach is used. This allows the growth rate of the entire
industry to be considered as opposed to the build-up capacity of individual technology developers.
Starting in 2030, a constant growth rate is applied to the output volumes of individual routes. This
allows the potential deployment of synthetic kerosene production technologies to be estimated taking
their 2030 status into account, but still allows investigation of how they could plausibly develop in the
future under a number of different scenarios.
The development of sustainable aviation fuels is heterogeneous and encompasses technologies at
different stages of technical maturity. To be used in commercial aircraft, aviation fuels need to be
ASTM certified. Today, only a limited number of sustainable aviation fuel (SAF) routes have this
certification, others are either currently in the certification process or are at an even earlier stage.

14 In order to achieve a 95% overall GHG reduction by 2050: https://www.government.nl/topics/climate-change/climate-policy

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Decarbonisation potential of synthetic kerosene
However, the scale up assessment reflects the potential production of synthetic kerosene fuel and the
same modelling approach is adopted regardless of whether a specific route is currently ASTM certified
or not.
Some conversion routes use alcohol intermediates, ethanol (from steel mill off gas) and methanol
(either from blue or green hydrogen), and these represent a potential pool of intermediate feedstock
available for jet synthesis. For this assessment, the production of the intermediate alcohols was
modelled separately from the jet fuel synthesis, reflecting the trends observed amongst technology
developers, where alcohol production plants are operated separately from jet synthesis plants. This
separation occurs because ethanol and methanol are versatile chemicals which have applications in
many industries, not just fuel synthesis.
Therefore, in line with Section 3.1, the following simplified set of synthetic kerosene conversion routes
are considered:
•
•
•

“Green FT”: Green hydrogen + CO2 routes to Fischer-Tropsch synthesis (routes 1-3).
“Green MtJ”: Green hydrogen + CO2 to methanol to jet synthesis (routes 4-6).
“CO to Jet”: Fermentation of CO to ethanol to jet synthesis (route 13) or CO + Fischer-Tropsch
synthesis (routes 14-15).

As explained above, routes involving blue hydrogen (routes 7-12) were not modelled in this ramp-up
assessment, due to the lack of current activities. Further information about the modelling
methodology and assumptions made can be found in Appendix A.

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Decarbonisation potential of synthetic kerosene

4 Results and analysis
4.1 Techno-economic modelling
4.1.1 Energy, cost and GHG emission results
In this section, we present the central case modelling outputs for route efficiency, levelised
production cost and lifecycle GHG emissions. Further results when varying key parameters are
explored in the sensitivity analysis in Appendix B. In this section, we first present the results for all
the CO2 to FT routes (1 – 3b and 7 – 9a) based around the central DAC case, before looking at the
DAC options (routes 3a-3e and 9a-9e). We then present the results for the recycled fossil CO routes
(13 – 15). Since very similar results were obtained for the methanol to jet routes as for the equivalent
FT routes, for the sake of brevity in this section, the results for the methanol to jet routes (4 – 6 and
10 – 12) are provided in Appendix B.
Figure 13 compares the energy efficiencies of the green and blue FT routes today and forecast to
2030 and 2050. Lower heating value (LHV) efficiencies from starting renewable power or natural gas
to synfuel products (a combination of similar synthetic fuels such jet, diesel, gasoline and naphtha)
generally lie within the range of 30 – 40%, although the DAC route is less efficient than routes using
point CO2 sources owing to the considerable electrical and heat energy required to capture CO2
from the atmosphere. For an explanation of DAC1 and DAC2, please refer to Table 5. The acronym
“PS” in the charts refers to Point Source capture of biogenic or fossil CO2.

Figure 13: LHV efficiency of FT routes by year

In general, blue routes are slightly more efficient today than green routes, but green routes show
greater improvements in efficiency over time meaning that by 2050 the green routes are as efficient
as their blue counterparts. This mainly reflects the higher level of maturity of steam methane
reforming compared with electrolysis. The small increase in efficiency of route 7 is explained by
improvements in carbon capture technology while the improvements to route 9 can be largely
explained by improvements to DAC. By contrast, electrolyser efficiency is expected to improve as
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Decarbonisation potential of synthetic kerosene
scales increase and further operating experience and process integration is achieved. Sensitivity tests
showing the effects of improving electrolyser efficiency and reduced electrolyser CAPEX are shown in
Appendix B. Most improvement is expected in the DAC routes (blue or green) given the relatively low
TRL of DAC technology and the implied capacity for technological and process improvements which
should be possible in the coming years.
Figure 14 provides a comparison of production costs across the FT routes over the target years and
these have been broken down across the value chains to highlight the most important contributors
to cost. For an explanation of DAC1 and DAC2, please refer to Table 5.

Within each route, the
columns are for 2020,
2030 and 2050 data
moving left to right

Figure 14: Production costs for FT routes by year

The values presented in Figure 14 show that the blue routes are initially lower cost than the
equivalent green routes. In 2020 green routes are roughly 3x more costly than their blue
counterparts, reflecting the much higher cost of renewable electricity relative to natural gas, even
when the need to sequester the CO2 emissions from SMR are taken into account. Falling renewable
electricity costs and improving efficiencies mean that by 2050 green routes are likely to be only ~12 –
15% more expensive than blue routes.
A sensitivity test was performed to analyse the impact of switching from SMR to ATR and whilst this
showed that the production costs are almost the same, ATR does offer some GHG improvements in
2030 and 2050 as this process has a higher CO2 capture rate and higher efficiencies (Appendix B).
DAC routes are considerably more expensive than routes using point source CO2, with the green
route using DAC (route 3) being nearly 1.7x the cost of green point source routes in 2020 (although
this differential falls to around 1.4x by 2050). Once again, DAC benefits from efficiency
improvements, as well as decreases in renewable electricity and green hydrogen costs in the DAC2
option.
An indicative pre-COVID price of fossil jet of €600 per tonne is also shown in Figure 14 (noting that
current fossil jet prices are lower than this level due to the pandemic). Both green and blue synthetic

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Decarbonisation potential of synthetic kerosene
routes are, and are expected to remain, significantly more expensive than fossil jet. By 2050 synthetic
kerosene is likely to still be 2 – 4x the cost of fossil kerosene today, depending on the route
considered. However, this does not account for any cost of carbon that may be attached to
conventional kerosene (or synthetic kerosene routes) in the future.
Figure 15 shows the production costs using different sources of energy for heat and power when
using high temperate DAC technology. The DAC technology modelled has a higher heat requirement
than low temperature absorption based DAC, which may also have options for heat integration.
However, HT DAC has been chosen here because it has more potential for rapid scale up given largescale equipment. Whilst overall synthetic kerosene chains involving DAC may look comparatively less
favourable today, there is a lot of potential for DAC cost improvements as the technology matures.

Within each route, the
columns are for 2020,
2030 and 2050 data
moving left to right

Figure 15: Comparison of production costs using different heat and electricity sources for DAC

Figure 16 presents the lifecycle GHG emissions associated with each of the FT routes, again broken
down by year and by element of the value chain. As would be expected, green routes generally
achieve very low GHG emissions with the biogenic and DAC routes each showing GHG emissions of
~5 gCO2e/MJ of fuel. Emissions when a fossil point source of CO2 is used are higher (~25 gCO2e/MJ of
fuel) reflecting the additional fossil gas required to capture the CO2 at the power plant. The burning
of this additional natural gas leads to both extra upstream and combustion emissions (because
although the CO2 that is released when the additional natural gas is burnt is mostly captured by the
power plant equipment, this additional captured fossil CO2 is also turned into jet fuel, ultimately
releasing additional fossil carbon to atmosphere, and hence needs to be fully accounted for).
GHG emissions for the blue routes are considerably higher than green routes, primarily owing to the
upstream emissions from fossil natural gas supplies15 and 10% of uncaptured CO2 when producing
blue hydrogen16. These two processes account for 62% and 38% of the emissions associated with
blue hydrogen production respectively. In contrast to the green cases, the highest emissions are
observed for DAC which is explained by the fact that in the blue routes, DAC is assumed to use
15

https://ec.europa.eu/jrc/en/publication/eur-scientific-and-technical-research-reports/jec-well-tank-report-v5
GMCG1 pathway, up to point of compression and dispensing
16
IEA GHG Technical Report 2017-02: Techno-Economic Evaluation of SMR Based Standalone (Merchant) Hydrogen Plant with CCS. Page 4.

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Decarbonisation potential of synthetic kerosene
natural gas and grid electricity as its energy sources (unlike the green routes). For explanation of
‘DAC1’ and ‘DAC2’, please refer to Table 5.
Note that the synthesis steps also require heat input for the RWGS reactor. In the blue routes, this is
provided by natural gas so there are synthesis emissions, but in the green routes this is provided by
green H2 so the synthesis step has minimal GHG emissions.
Within each route, the columns
are for 2020, 2030 and 2050
data moving left to right

Figure 16: Lifecycle GHG emissions by FT route and year

RED II specifies a fossil transport counterfactual of 94 gCO2e/MJ. Given the EU context, this level has
been used in this analysis, rather than the value of 89 gCO2e/MJ used by CORSIA. RED II has already
set a minimum GHG saving threshold of 70% for renewable fuels of non-biological origin, which
would apply to the green routes, requiring <28.5 gCO2e/MJ SAF. However, a minimum GHG saving
threshold or GHG methodology has not yet been finalised for ‘recycled carbon fuel’ routes, which
would likely impact many/most of the blue H2 + CO2 routes (route 7-12) and fossil CO routes (routes
13-15). These will be set at EU-level later in 2021. There is uncertainty over whether blue hydrogen
with DAC (route 9) would count as a ‘recycled carbon fuel’.
All routes, except the blue H2 + DAC route 9, have GHG emissions below the RED II fossil transport
counterfactual in 2020. However, none of the blue routes can achieve above a 55% GHG saving in
any year, while all the green routes have GHG savings above the 70% saving threshold in all years.
Note that the blue hydrogen production emissions alone within routes 7-12 exceed 28.5 gCO2e/MJ
SAF level, reflecting the impact of the upstream natural gas emissions, reforming efficiency losses
and the 10% of fossil CO2 that is assumed not to be captured in reforming, therefore highlighting the
fundamental emissions challenge facing routes 7-12. Depending on the level of the RED II threshold
for recycled carbon fuels, all blue routes (routes 7-12) might be ruled ineligible under RED II.
Furthermore, all the point source CO2 routes (routes 1-2, 4-5, 7-8, 10-11) are assuming that the
counterfactual fate of the CO2, if not converted into fuels, would be release to atmosphere and not
sequestered. Whilst potential RED II changes during 2021 are unlikely to address different
counterfactuals for CO2 feedstocks (rule changes for ‘recycled carbon fuels’ are only likely to focus on

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Decarbonisation potential of synthetic kerosene
energy-containing feedstocks such as waste fossil CO gases), long-term decarbonisation of point
sources and the roll-out of CCS could lead to this atmospheric release assumption being challenged.
If the counterfactual were CCS, and EU rules in a subsequent iteration of RED II (or post 2030) were
changed, then all point source CO2 routes to fuels would have extremely high GHG emissions (likely
higher emissions than conventional fossil jet, due to release of feedstock CO2 to atmosphere rather
than sequestration).
DAC routes would however likely still have the same GHG emissions as presented in this section, as
the building of DAC plants for fuels production is discretionary and the counterfactual that CO2 stays
in the atmosphere is unlikely to change. Figure 17 shows the associated GHG emissions for the
different DAC options (as described in Table 5). DAC1 is unable to meet the 70% saving threshold for
the green route in all years, given the use of natural gas heating and grid power. Green hydrogen
routes utilising DAC will therefore likely be forced to not use the DAC1 configuration option if they
wish to be compliant with RED II, and will have to focus on DAC 2-5 options instead. DAC 4-5 have
emissions closer to the threshold, due to the use of blue H2 in DAC heating.
DAC1 is also a worst case for the blue routes, and would appear to likely be ineligible under RED II
regardless of where the threshold is set for recycled carbon fuels. None of the other DAC options can
achieve more than a 55% GHG saving when using blue hydrogen.
Within each route, the
columns are for 2020,
2030 and 2050 data
moving left to right

Figure 17: Comparison of GHG emissions using different heat and electricity sources for DAC

The results for the recycled fossil CO routes are presented in the following charts. They are modelled
using as similar an approach as possible to the FT routes above, with as many common assumptions
used across the datasets as possible. However, they are not completely comparable with the CO2
routes or each other due to inherent differences in the plant configurations. For example, the project
developers for both CO routes envisage much larger scale plants than those modelled in the green or
blue FT routes above (by 2050, ~17x the size for the CO + FT routes and ~3x the size for the CO
fermentation route). These CO routes therefore benefit from economies of scale, and a significant
proportion the CAPEX for these plants are based on retrofitting equipment to existing facilities rather

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Decarbonisation potential of synthetic kerosene
than building new greenfield plants. Furthermore, the developer data for routes 14-15 did not
include a full mass balance, and assumptions on FT yields17 and CO2 capture rates appear to be at the
most optimistic end of feasible ranges, compared to more modest assumptions taken in our analysis
of routes 1-12.
These recycled fossil CO routes also utilise a degree of heat integration and recycling of materials
which has not been included for routes with CO2 as a feedstock. For the recycled fossil CO routes,
grid electricity has been modelled wherever electricity is used and natural gas has been used
wherever a heat source is used. However these routes are not necessarily tied to these energy
sources and so it is possible that green hydrogen and renewable electricity could also be used. For
the fossil CO + FT routes (routes 14-15), only data for 2030 was available from the project developer,
as their assumption was that by 2050 steel making in the EU will have largely decarbonised
(switching to using hydrogen, electricity, or biomass methods) and so the steel mill waste fossil CO
gas stream is unlikely to be available. There also may be potential for input CO2 sources (with watergas shift) to replace steel mill fossil CO over time, i.e. FT synthesis plants changing their carbon
source, but this has not been explicitly modelled in this study.
The recycled fossil CO route energy efficiencies are presented in Figure 18 which points to higher
levels of efficiency than those achieved for routes 1-12 using CO2 as a feedstock. This is explained by
the fact that RWGS is no longer required, and the CO feedstock contains considerable energy already
(unlike CO2 which contains no energy). For route 15, the input natural gas used to generate blue
hydrogen is included in the overall pathway values, for comparability with routes 1-12.

Figure 18: LHV efficiency of recycled fossil CO routes (13 - 15) by year

17 Becker et al. (2012) “Production of Fischer–Tropsch liquid fuels from high temperature solid oxide co-electrolysis units”,

https://www.sciencedirect.com/science/article/abs/pii/S0360544212006792 Becker et al. state that FT reactor single-pass conversion rates
for CO typically range from 60-90%, with higher rates having lower selectivity to longer hydrocarbons. 80% is chosen as a baseline
performance value in their study, and matches the assumption taken for routes 1-12 in this study, whereas data for routes 14-15 are at the
top of this range. However, routes 14-15 are assuming much larger-scale FT than in routes 1-12, and therefore recycle loops through the FT
reactor may be viable, allowing higher conversion rates to be achieved than in single-pass configurations.

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Decarbonisation potential of synthetic kerosene

Figure 19 presents the calculated costs for the CO fermentation + ethanol to jet route. Costs fall
considerably between 2020 and 2050 owing mainly to reducing capital expenditure resulting from
e.g. economies of scale and falling O&M costs/learning, but still remain above today’s fossil jet prices
by 2050. The microbial protein co-product made during fermentation could be an additional revenue
stream, as it could be valued at up to €1340/tonne of protein (equivalent to €228 per tonne jet fuel),
but this has not been explicitly factored into these production costs as the market for this co-product
is still uncertain.

Figure 19: Production costs for the CO fermentation + ETJ (Route 13)

The costs of the CO + FT routes are shown in Figure 20. The €/tonne cost of steel mill CO gases been
taken to be equivalent to that used in route 13 for consistency. The WGS reaction produces a
substantial amount of by-product CO2 which the project developer plans to capture (at a very high %
rate) and sequester, and the costs of this have been included in Figure 20 and in the GHG emissions
saving shown in Figure 24. The downstream cost of sequestration used here is consistent with that
used for sequestering CO2 produced from the SMR plant during the synthesis of blue hydrogen. All
the costs associated with the production of the blue hydrogen have been encompassed within the
single ‘blue hydrogen’ part of the stack chart in the ‘CO + Blue H2 FT’ column (route 15), and include
costs for natural gas, annualised CAPEX, fixed and variable OPEX and the downstream costs of
sequestering 90% of the CO2 produced – hence why the downstream transport and storage of CO2 is
not split out for route 15, given blue hydrogen is purchased by the FT plant.

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Decarbonisation potential of synthetic kerosene

Figure 20: Comparative production costs for CO + FT in 2030 (Routes 14 & 15)

Direct GHG emissions will be produced during the production of synthetic kerosene via the recycled
fossil CO routes (13-15). However, following a recycled carbon fuel methodology proposed by JRC,
the relative importance of these should be considered in the context of a counterfactual, i.e. what
would have happened to the steel mill gases if they had not been used to produce synthetic fuels.

Figure 21: Illustration of CO counterfactual cases, and synthetic kerosene production

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Decarbonisation potential of synthetic kerosene
Three counterfactual options are shown in Figure 21 and described below:
1. Flaring of the steel mill CO gas – this case has not been shown on separate charts, but the net
GHG emissions of the synthetic kerosene produced would just include the direct emissions
from the processes required to generate the fuel, as there are no displaced emissions.
2. Steel mill CO gases are combusted to produce electricity for the grid, using 35% efficiency at
a power plant with unabated emissions (Figure 22 and Figure 24).
3. Steel mill CO gases are combusted to produce electricity for the grid using a 25% efficiency at
a power plant with abated emissions (90% carbon capture rate – the lower efficiency taking
into account the additional energy required for CCS). (Figure 23 and Figure 25).
For counterfactuals 2 and 3, more grid electricity generation is required to replace the lost power
plant generation when steel mill CO gases are diverted from electricity to synthetic kerosene
production. Following a recycled carbon fuel methodology proposed by JRC, these additional grid
emissions are displaced emissions that should also be accounted for in the synthetic kerosene GHG
emissions calculations (because they were previously a GHG saving made when generating power).
In the unabated case 2, the carbon dioxide that would have been released to the atmosphere upon
steel mill CO gas combustion for electricity generation at the steel mill's power unit is the same
carbon dioxide that is released to atmosphere upon combustion of the synthetic kerosene plus any
CO2 released in production of the synthetic kerosene. Therefore, as long as the carbon emissions
liability remains with the steel manufacturer, this carbon can be utilised in electricity generation or
synthetic kerosene, without having to account for it upon combustion in either electricity generation
or jet engines. However, if the steel mill were to claim a reduction in its carbon liability (i.e. the
counterfactual becomes more abated / case 3), this benefit would shrink or disappear. Or if the steel
mill were to sell captured CO2 after power generation for making fuels via e.g. route 2, this benefit
would also disappear (as geological sequestration of the CO2 is not occuring).
Following the RED II methodology as applied to biofuels, and assuming similar rules will apply to the
direct processing emissions of recycled carbon fuels, the microbial protein generated in route 13 as a
co-product has a LHV energy content, and so 8% of the process emissions have been allocated to this
co-product in proportion to its LHV energy content vs the overall energy content of all products and
co-products (including synthetic fuels). This has slightly reduced some of the emissions shown in both
Figure 22 and Figure 23.
Figure 22 shows the GHG emissions for the CO fermentation + ETJ (route 13) where the
counterfactual is an unabated power plant at 35% efficiency. Note that in this unabated
counterfactual scenario, the sum of the fuel and processing CO2 emissions equals the power plant
CO2 emissions (and therefore cancel out). The direct emissions from inputs to synthetic kerosene
production are shown without dotted outlines.
Figure 22 demonstrates the approach used to calculate the net GHG emissions for the recycled fossil
CO-based synthetic kerosene routes in this study, using the following formula (with terms A to D
corresponding to the green labels in Figure 21):
CO-based synthetic kerosene net GHG emissions (red dot)
= A. Emissions from inputs to synfuel processing & distribution (left-hand bars without dotted lines)
+ B. CO2 released in synfuel processing & combustion (left-hand orange/yellow bars with dotted lines)

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Decarbonisation potential of synthetic kerosene
– C. CO2 released in the counterfactual power generation use (right-hand light grey bar above x-axis)
+ D. Additional grid emissions from displacement of counterfactual power generation (right-hand
dark grey bar below x-axis – these are shown as a negative value on the charts, since these are
effectively a benefit of the counterfactual scenario emissions, and therefore are an added impact of
synthetic kerosene production).
As demonstrated in Figure 22, the only element not covered is conventional fossil jet production and
use, as this is what the synthetic kerosene net GHG emissions can now be compared against.
Based on the chosen Netherlands grid factor, the GHG savings today if only including processing
inputs would only be around 55%, and inclusion of displaced emissions today (were this change to
RED II decided and already in force) would lead to net emissions above the REDII fossil benchmark.
However, the net GHG emissions for synthetic kerosene are expected to fall dramatically over time,
mainly as a result of electricity grid decarbonisation over time (reducing the direct process emissions
and reducing the displaced feedstock emissions associated with diverting CO from electricity to
synthetic kerosene production), plus switching from natural gas to electricity for steam production.
By 2030, both direct and displaced emissions will have fallen significantly, leading to net emissions
near 70%. This scenario is presuming the unabated counterfactual is still the correct counterfactual
to take in the calculations over time.

Figure 22: GHG emissions for the CO fermentation + ETJ (Route 13) where the counterfactual is steel
mill CO gas use in an unabated power plant at 35% efficiency

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Decarbonisation potential of synthetic kerosene
Figure 23 shows the GHG emissions for the CO fermentation + ETJ (route 13) where the
counterfactual is an abated power plant at 25% efficiency and 90% CCS. In this abated counterfactual
scenario, the power plant CO2 emissions are significantly reduced, and the displaced grid emissions
are slightly reduced (due to lower power generation efficiency). The emissions from synthetic
kerosene inputs, fuel combustion emissions and processing emissions remain unchanged from the
previous counterfactual scenario.
Net GHG emissions for synthetic kerosene are significantly above the RED II fossil transport
benchmark in all years, due to the release of fossil CO2 to atmosphere compared to geological
sequestration via power generation. There is a small saving from avoiding the 10% uncaptured CO2 at
the power plant being released to atmosphere, but when making jet fuel all the carbon in the
feedstock is released to atmosphere (whether vented in the process, or in jet fuel combustion). An
abated counterfactual will therefore not lead to compliance with RED II, regardless of the threshold
level – but power plants will increasingly become abated over time, i.e. this counterfactual will
become more relevant to 2050.

Figure 23: GHG emissions for the CO fermentation + ETJ (Route 13) where the counterfactual is steel
mill CO gas use in an abated power plant at 25% efficiency and 90% capture rate

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Decarbonisation potential of synthetic kerosene
Figure 24 and Figure 25 present the lifecycle GHG emissions for the CO + FT routes (note only data
for 2030 was provided for these routes). Figure 24 presents the emissions in a scenario where an
unabated power plant is the counterfactual (most likely to be valid in the near- to mid-term), and
Focusing just on the processing input emissions, Figure 24 shows that both CO + FT routes (14 and
15) are likely to achieve GHG savings of above 70% in 2030. There are also large fuel combustion
emissions, and small process CO2 emissions (as the large majority of CO2 released in processing is
captured and sequestered). However, the counterfactual power plant has high emissions to
atmosphere, particularly in the route 14 counterfactual, where these emissions are especially high
due to the high CO input per tonne of jet production in route 14 (due to WGS). These power plant
CO2 emissions either offset the fuel and process CO2 emissions in route 15, or significantly more than
offset them in route 14, leading to a net negative GHG emissions for route 14.

Figure 24: Comparative lifecycle GHG emissions for CO + FT routes in 2030 (14 and 15) where the
counterfactual is steel mill CO gas use in an unabated power plant at 35% efficiency

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Decarbonisation potential of synthetic kerosene
Figure 25 illustrates the emissions if an abated power plant with a 90% CO2 capture rate is the
counterfactual (most likely to be valid in the mid- to long-term as CCS is rolled out). The emissions
from synthetic kerosene inputs, fuel combustion emissions and processing CO2 emissions remain
unchanged between Figure 24 and Figure 25. However, in this abated counterfactual scenario, the
power plant CO2 emissions are significantly reduced, and the displaced grid emissions are slightly
reduced (due to lower power generation efficiency).
Net GHG emissions for synthetic kerosene are close to the RED II fossil transport benchmark in 2030
(i.e. GHG savings are small or non-existent), due to the release of fossil CO2 to atmosphere compared
to geological sequestration via power generation. Power plants will increasingly become abated over
time, i.e. this counterfactual will become increasingly relevant in the period 2030 to 2050. The
correct counterfactual to use and how it might need to evolve over time is a policy decision, and for
those recycled carbon fuels in scope of REDII, this is likely to be determined by REDII delegated act
during 2021. A breakdown of energy inputs and a sensitivity analysis is provided in Appendix B.

Figure 25: Comparative lifecycle GHG emissions for CO + FT routes in 2030 (14 and 15) where the
counterfactual is steel mill CO gas use in an abated power plant at 25% efficiency with a 90% capture
rate

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Decarbonisation potential of synthetic kerosene

4.1.2 GHG abatement cost results
Figure 26 presents the cost of GHG abatement for each of the FT routes. These abatement costs are
generally lower for blue routes than for green routes today, suggesting that the lower costs of blue
routes outweighs their significantly higher GHG emissions – but this situation is reversed by 2050 as
green routes costs fall. There is considerable overlap between green and blue abatement costs in
2030. Note that for route 9, GHG emissions are higher than for fossil kerosene in 2020 and 2030 so
abatement costs have been omitted, and route 9 abatement costs in 2050 remain high, due to the
small GHG savings.

Figure 26: GHG abatement costs for FT routes

The abatement cost levels achieved in 2050 for the most attractive routes are similar to the levels
anticipated for biofuels (see Section 4.2.7) and in the same range as biomass power production with
CCS. However, current abatement costs are considerably higher than current carbon prices or policy
abatement costs in many other sectors of the economy.
Green and blue routes using DAC also have abatement costs that are higher than just using DAC with
CCS, suggesting that from a policy perspective, other considerations such as airline fuel security or
customer pressure, CCS constraints or aviation non-CO2 effect benefits from using cleaner burning
SAF may have to be considered in addition to just the GHG abatement cost if DAC is to be used in jet
fuel production and not just CCS.
Figure 27 presents the GHG abatement costs for methanol routes and reflects the fact that these
have very similar performance from a cost and GHG perspective to the FT routes. Note that for route
12, emissions in 2020 and 2030 are higher than for fossil kerosene so abatement costs have been
omitted, and route 12 abatement costs in 2050 remain high at~€3750/tCO2e, well above the y-axis
range given.

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Decarbonisation potential of synthetic kerosene

Figure 27: GHG abatement costs for methanol routes

Figure 28 presents the cost of GHG abatement for each of the CO based routes in 2030, assuming an
unabated counterfactual. The fermentation route could achieve lower abatement costs compared
with the CO2 routes in 2030. Routes 14 and 15 show even lower GHG abatement costs in 2030,
particularly for CO + WGS, due to the large amount of CO2 captured and sequestered compared to
the unabated power generation counterfactual. However, if an abated counterfactual were used,
GHG emissions for routes 13 and 15 in 2030 are higher than fossil kerosene (so there is no
abatement), and route 14 has an increased abatement cost of ~€450/tCO2e, due to the significant fall
in GHG savings.

Figure 28: GHG abatement costs for CO routes (considering an unabated counterfactual)

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Decarbonisation potential of synthetic kerosene

4.1.3 Potential impact on ticket prices
In this section the implied cost to passengers associated with different fuel routes is estimated based
on the initial assumption that airlines would pass on the full additional fuel cost to passengers on
flights which refuel with a synthetic kerosene blend. The cost ranges for each set of routes is set out
in Table 6, using 2030 data from this study.
Table 6: Assumed kerosene costs in €/tonne in 2030

Assumption

Value

Cost of conventional fossil kerosene
Green synthetic kerosene cost (high)
Green synthetic kerosene cost (low)
Blue synthetic kerosene cost (high)
Blue synthetic kerosene cost (low)
CO based synthetic kerosene cost (high)
CO based synthetic kerosene cost (low)

600
3200
2300
1900
1500
1300
1000

Based on the estimated additional fuel cost per tonne compared with conventional fossil kerosene,
and two illustrative flights18, an estimation was made of the additional cost of fuel per flight:
•
•

Short-haul flight from Amsterdam to Rome on Boeing 737: flight distance 1,300 km, 160
passengers, 5 tonnes fuel burnt
Long-haul flight from Amsterdam to New York on Boeing 777: flight distance 5,800 km, 310
passengers, 47 tonnes fuel burnt

Assuming that the total added fuel cost for the flight is passed on equally to all passengers, the
additional cost per passenger per flight for green synthetic kerosene routes is illustrated in Figure 29.
Bars illustrate the average synthetic kerosene costs, based on the average of low and high costs,
whereas the uncertainty intervals refer to the high and low cost scenarios.

Additional price
(€/passenger/flight)

70

66

60
50

44

40
30

22

20
10

14

9

5

0
7%

14%

21%

SAF blend percentage
Short-haul (Amsterdam-Rome)

Long-haul (Amsterdam-New York)

Figure 29: Additional flight price per passenger in case of green synthetic kerosene routes cost fully
passed-on

18 Aircraft information from Source: ICCT, 2018, Transatlantic Airline Fuel Efficiency Ranking 2017,

https://theicct.org/sites/default/files/publications/Transatlantic_Fuel_Efficiency_Ranking_20180912.pdf

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Decarbonisation potential of synthetic kerosene
The equivalent figures for blue synthetic kerosene routes in presented in
Additional price
(€/passenger/flight)

70
60
50

40

33

30

22

20
10

11

2

7

5

0
7%

14%

21%

SAF blend percentage
Short-haul (Amsterdam-Rome)

Long-haul (Amsterdam-New York)

Figure 30, while the figures for CO routes appear in Figure 31.

Additional price
(€/passenger/flight)

70
60
50

40

33

30

22

20
10

11

2

7

5

0
7%

14%

21%

SAF blend percentage
Short-haul (Amsterdam-Rome)

Long-haul (Amsterdam-New York)

Figure 30: Additional flight price per passenger in case of blue synthetic kerosene routes cost fully
passed-on

Additional price
(€/passenger/flight)

70
60
50

40
30
20
10

2

5

1

10

15
3

0
7%

14%

21%

SAF blend percentage
Short-haul (Amsterdam-Rome)

Long-haul (Amsterdam-New York)

Figure 31: Additional flight price per passenger in case of CO synthetic kerosene routes cost fully
passed-on

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Decarbonisation potential of synthetic kerosene
Under the 14% blend scenario, the implied increase on the short-haul ticket price is between 2% for
CO routes and 9% for green fuel routes (assuming a one-way ticket price of €10019). Meanwhile an
increase on the long-haul ticket price of between 3% and 11% (assuming a one-way ticket price of
€400) for the same fuel pathways at 14% blending could be expected.

4.2 Capacity ramp-up and feedstock modelling
4.2.1 Status of synthetic kerosene routes and aviation industry
The scale up rate of synthetic kerosene routes depends on resource availability, ongoing
commercialisation activities and current market trends. The current number of developers and
ongoing or announced number of projects gives an indication of the deployment trends of individual
synthetic kerosene routes. We assume that technology developers will scale up their technology to
commercial scale and license their technologies once mature, and this will considerably drive the
increase of synthetic kerosene supply.
The global nature of the technologies means that developments need to be assessed at a global scale.
The data used for the ramp up potential assessment was collected at both European and global scale.
Currently Europe dominates R&D activities. However, it is assumed that once the technology is scaled
up and suitable to be deployed at commercial scale, technology developers are likely to start up new
commercial plants outside of Europe.

23

8

2

1

(routes 13-15)

(routes 1-3)

(routes 4-6)

(routes 4-6)

CO to Jet

Green FT

PtL MeOH

Green MTJ

Figure 32 Number of e-synthetic fuel technology developers globally by route

19 These are indicative prices for Amsterdam-Rom one-way and Amsterdam-New York one-way at the end of January 2020, booked 2

months in advance. Prices have been taken from https://www.skyscanner.net/. Prices can vary significantly depending on airline, booking
date, flight date, flight time, economy vs business class.

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Decarbonisation potential of synthetic kerosene

Methanol to Jet synthesis (MtJ)
Only one pilot project, KEROSyN100 led by the Advanced Energy Systems Institute at the University of
Bremen in Germany, was identified for this route. Given the limited activity observed today (the route
is still to be ASTM certified), the methodology adopted in the ramp up model will predict limited scale
up potential for this conversion route. However, despite the very limited number of current MtJ
technology developers, there is still potential for faster scale-up of this route, due to the large number
of initiatives in power-to-methanol production, with Europe dominating development projects (Table
3).
Power-to-methanol is still an early-stage technology, with the majority of projects identified at pilot or
demonstration scale. However, we also identified a small number of commercial scale projects
particularly in industrial clusters. For example, the Port of Antwerp project aims to synthesise
methanol from point source CO2, for use in maritime and chemicals manufacture. The potential scale
up of e-methanol for jet synthesis therefore needs to be considered in the context of wider industry
activities and availability of e-methanol.
Today, the production of blue methanol is not practiced. As stated in section 3.1.4, lower carbon fossil
methanol production is mainly driven by existing large fossil methanol players who produce methanol
from natural gas and have installed carbon recovery units to recycle carbon and increase their output.
Their facilities are therefore already at commercial scale and produce large volumes of product, but
this is not blue methanol involving hydrogen with CCS. The addition of CCS to existing large-scale
hydrogen facilities could happen relatively quickly, and could represent significant resource availability
for the subsequent methanol-to-jet steps. However, to date, no operational or announced projects
involve methanol production using a source of blue hydrogen produced with CCS. Hence, methanolto-jet via blue methanol (routes 10-12) was not modelled in the ramp-up part of this study.

Fischer-Tropsch synthesis
Europe is leading the development of renewable power-to-liquids via Fischer-Tropsch synthesis
(routes 1-3). Most developments identified are at small scale (pilot and demonstration plants), but
some developers have also announced commercial scale projects (Table 2).
The use of blue hydrogen as input is a potential alternative to renewable power-to-FT liquids. Today,
interest in the blue hydrogen + FT option (routes 7-9) appears very limited, and no technology
developers have announced plans for blue hydrogen + FT jet plants. For this reason, in order to align
with the modelling methodology adopted for other conversion technologies, the scale up potential of
these routes were not modelled in this assessment. There are some limitations linked to this approach
since new projects could potentially be announced by technology developers over the next few years,
although this will also depend on their categorisation and GHG savings under RED II or other policies.
Finally, one technology developer has announced a large-scale Fischer-Tropsch to jet plant using steel
mill CO as the main carbon source (route 14). This conversion process produces hydrogen via the WGS
reaction prior to the Fischer-Tropsch synthesis. Alternatively, the CO could be reacted with purchased
hydrogen to avoid the WGS reaction (route 15). In this assessment, this route has been modelled as
“CO + Fischer-Tropsch synthesis” and the supply ramp up has been included in the “CO to Jet” category.

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Decarbonisation potential of synthetic kerosene
Developers deploying FT routes via fossil waste gases are likely to build larger scale plants even for
First of a kind (FOAK) commercial plants, given that the component technologies deployed are proven
at scale. For this reason, starting up a new CO + Fischer-Tropsch plant would have a considerable
impact on the capacity scale up of this route.

Steel mill gas fermentation to ethanol to jet route
Similarly to the methanol-to-jet synthesis, the scale up potential of this route is treated in two separate
parts. First steel mill gas fermentation produces the ethanol intermediate. LanzaTech is the pioneer of
this conversion route and has formed partnerships with several steel producers.
The ethanol intermediate can then be upgraded to jet in a second step. Lanzatech has formed a
partnership with Pacific Northwest National Laboratory (PNNL) and has spun-out a separate company,
LanzaJet, to focus on the commercialisation of alcohol-to-jet, including integrated production onsite
alongside ethanol production.

4.2.2 Short- and long-term outlook
The short and long-term scale up potential of synthetic kerosene routes is heavily influenced by
ongoing activity and project developments. Depending on the time scale analysed, different
approaches are used to estimate the synthetic kerosene ramp up potential, and as discussed in Section
3.2.2, two scenarios were developed to estimate the scale up of synthetic kerosene to 2030 and 2050
in Europe and globally. As explained above, routes involving blue hydrogen (routes 7-12) were not
modelled in this ramp-up assessment, due to the lack of current activities in these routes.
Europe Slow Growth

Europe Fast Growth

Global Slow Growth

Global Fast Growth

40

Jet fuel [ Mtonnes / year ]

35
30
25
20

15
10
5

Figure 33: Cumulative capacity of all synthetic kerosene production routes to 2050.

Figure 33 shows the cumulative capacity build up in each of the scenarios to 2050. In the European
fast growth scenario, the cumulative number of new synthetic kerosene plants increases from 6 in
2030 to 232 in 2050, with the green FT routes dominating the picture. These plant numbers are
indicative, as they are based on the plant scales included in the model. Whilst these are representative
of developers’ planned commercial scale plants today, in the future developers may choose smaller or
larger plants depending on, among other things, the availability of resources, e.g. blue or green

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Decarbonisation potential of synthetic kerosene
hydrogen, and progression in technology minimum economic scales. Note that Europe remains a
significant contributor to global supply to 2050, but this reflects how the model is designed which tends
to perpetuate the split apparent in 2030.
30

Green MtJ (routes (4-6)

Green FT (routes 1-3)

CO to Jet (routes 13-15)

TOTAL

Jet fuel [ Mtonnes / year ]

25

20

15

10

5

Figure 34: Route breakdown of synthetic kerosene fuels in Europe to 2050 under the fast growth
scenario. Note that the CO to Jet route includes the CO fermentation to jet and the CO + FischerTropsch synthesis routes. The ramp up results of alternative scenarios are presented in Appendix A

Figure 34 shows the breakdown of the overall European synthetic kerosene supply by route type to
2050 with the global outlook following a similar trend. Under the fast growth scenarios, the synthetic
kerosene production in 2050 is estimated to reach 27 Mt/yr in Europe and 36 Mt/yr globally. For
comparison, in the International Energy Agency’s (IEA) B2DS scenario20, which aims to achieve netzero emissions by 2060, global SAF demand in 2060 reaches 150 Mt/yr corresponding to 70% of the
total aviation fuel demand (although this covers a range of SAF routes including synthetic jet).
The starting point for growth in the period 2030 – 2050 is based on the 2030 outlook, which in turn is
based on the current state of the industry. Hence, routes that are the nearest to commercialisation
today are likely to remain dominant in 2030 unless the emerging routes rapidly gain developers and
realise new large projects. Based on the modelling approach, the production of synthetic kerosene in
Europe is estimated to be able to reach 970 ktonnes/yr in 2030. This exceeds the implied demand
under a number of 2030 mandates or targets being discussed in Europe currently: the EU’s ReFuelEU
0.7% mandate for synthetic jet represents ~300 ktonnes/yr; the German 2% mandate of for synthetic
kerosene represents ~200 ktonnes/yr; and the Dutch 14% target for all SAF represents ~700
ktonnes/yr.
In 2030, the green FT route dominates the fast growth scenario for Europe, representing approximately
36% of the total synthetic kerosene supply. The methanol-to-jet route makes up the smallest share of
20 In the B2DS scenario “technology improvements and deployment are pushed to their maximum practicable limits across the energy

system in order to achieve net-zero emissions by 2060 and to stay net zero or below thereafter, without requiring unforeseen technology
breakthroughs or limiting economic growth”.

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Decarbonisation potential of synthetic kerosene
the European synthetic kerosene supply, 6%, given the very early stage of this technology today. Since
Europe dominates global production of green FT jet today, this is expected to remain the case in the
short term.
At global scale, the picture in 2030 is slightly different, with the total production capacity predicted to
reach approximately 1.3 Million tonnes under the fast growth scenario with the CO to jet and the green
FT routes predicted to supply approximately 35% and 61% of the total synthetic kerosene production
respectively.
For modelling purposes, CO based routes (CO fermentation + ATJ in route 13 and CO + FT synthesis in
routes 14-15) were grouped together under the “CO to Jet” classification.
The CO fermentation to jet route consists of two main conversion steps. First the fermentation of CO
waste gas to an ethanol intermediate, followed by upgrading conversion to jet via the alcohol-to-jet
process. Our analysis projects strong capacity scale up potential for route 13 based on current ATJ
technology developers being able to rely on a broad pool of alcohols, including advanced ethanol from
biogenic or from waste fossil feedstocks (Figure 35). This suggest that the jet synthesis step is unlikely
to be the bottleneck in the scale up of the CO to jet route. Instead, the build-up rate of the initial CO
fermentation step will likely limit the rate of growth of this route, since the model currently includes
LanzaTech as the sole technology developer.
In the European fast growth scenario, CO + FT routes (routes 14+15) could represent about 24% of the
total synthetic kerosene supply in 2050. This is based on one known large-scale project today,
however, this number could be considerably higher if more technology developers commission
projects before 2030. Considerations linked to the availability of CO waste gases will be discussed in
the feedstock section below.
EU ATJ fast growth

EU ATJ slow growth

Global ATJ fast growth

Global ATJ slow growth

70

Jet fuel [ Mtonnes / year ]

60
50
40
30
20
10

Figure 35: Capacity scale up of alcohol-to-jet using advanced ethanol (lignocellulosic, MSW) to 2050.

The higher growth rate attributed to the green FT routes means that by 2050, in the fast growth
scenario, this route is estimated to represent 57% of the total synthetic kerosene supply at both Europe

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Decarbonisation potential of synthetic kerosene
and global level. While the number of power-to-jet producers is still relatively small today (1 for MtJ
and 8 for PtL FT), ongoing activity in the wider power-to-liquids context and interest for a wide range
of industries could considerably accelerate the scale up of these technologies.
The methodology applied takes a conservative approach to model synthetic kerosene technologies at
an early stage of development. Methanol-to-Jet is an emerging technology with limited activity to date,
the ramp up of this route to 2030 is therefore relatively small. Beyond 2030, the 21% annual growth
rate applied reflects the possibility of new players entering the market, and faster growth rate of new
plants based on existing activity. As discussed above, the large-scale deployment of the methanol-tojet routes is linked to developments in the wider power-to-liquids field, in particular power-tomethanol, and the aviation industry has demonstrated growing interest in the power-to-methanol
technology by joining other technology developers involved in these types of projects. Earlier entry
into the market of new players could accelerate the overall ramp up to 2050. Contrary to the CO
fermentation to jet route, in this case the factor limiting growth is the jet synthesis step rather than
the production of the methanol intermediate. As stated in section 3.2.2, no ongoing or planned
projects were identified for the blue FT or blue methanol synthesis, so the ramp up for these routes
(routes 7-12) are therefore not modelled in the supply model to 2050. This assessment is based on
today’s picture, which reflects the considerable uncertainty amongst technology developer around
whether blue hydrogen routes will receive favourable policy treatment. If there are positive policy
signals that blue hydrogen + CO2 routes to synthetic kerosene are to be considered as sufficiently low
carbon, scale up could be achieved quickly given the relatively large nameplate capacities of blue FT
and blue MTJ plants and the abundance of natural gas. Even interest from a relatively small group of
players between now and 2030 could significantly increase the supply of jet from this route.

4.2.3 Resource availability
The sustainable scale up of synthetic kerosene capacity will be critically dependent on there being
sufficient supply of the inputs such as renewable power and natural gas but also intermediate
feedstocks in the case of the alcohol-based routes. The following section addresses the implications of
resource availability on the scale up scenarios of synthetic kerosene.

Renewable Electricity
The fast growth scenarios show that by 2030 an estimated 16 TWh/year in Europe and 21 TWh/year
of renewable electricity globally would be required to supply the green hydrogen based synthetic
kerosene routes as predicted by the ramp up model (Figure 36). Wind Europe’s central scenario to
2030 estimates 888 TWh/year of renewable power supply from onshore and offshore wind-power in
Europe by 203021. The IEA’s Sustainable Development Scenario estimates about 15,000 TWh/year for
all renewable power generation globally by 203022.
These numbers indicate that to 2030 demand for electricity for synthetic kerosene is likely to be small
and not lead to significant competition with demand in other sectors.

21 Wind Europe, (2017), available at: https://windeurope.org/wp-content/uploads/files/about-wind/reports/Wind-energy-in-Europe-

Scenarios-for-2030.pdf
22 IEA, Available at: https://www.iea.org/reports/renewable-power

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Decarbonisation potential of synthetic kerosene
25.0

Fast growth Europe

Feedstock requirements (TWh)

21

Slow growth Europe

20.0

Fast growth global
16

Slow growth global

15.0
13
12

10.0

5.0

0.0

Renewable electricity demand

Figure 36: Renewable Electricity requirements (TWh) in 2030 for all scenarios.

To be economically efficient, synfuel conversion plants need to have access to a supply of low-cost
renewable power with high full load hours (FLh). Analysis of synfuel production costs based on hybrid
PV and wind systems by Breyer and Fasihi23 shows that synfuels plants should ideally be located in
areas with high FLh if they are to achieve lowest production costs and limited storage requirements
(see Figure 37). These are typically areas with both high PV and wind capacity e.g. Middle East and
North Africa, where renewable power is cheap and supply potentially higher than local demand24.

Figure 37: Hybrid PV-Wind cumulative FLh in 200525

23 Direct Air Capture of CO : A Key Technology for Ambitious CC Mitigation 2019 Joule 3(9) Breyer and Fasihi
2
24 Role of e-fuels in the European transport system - Literature review, Concawe (2020), available at: https://www.concawe.eu/wp-

content/uploads/Rpt_19-14.pdf
25 Direct Air Capture of CO : A Key Technology for Ambitious CC Mitigation 2019 Joule 3(9) Breyer and Fasihi
2

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Decarbonisation potential of synthetic kerosene
Power can also be supplied through the main electricity grid but this would result in hydrogen which
is not fully green until such time as the grid is completely decarbonised (nearer 2050).
Competition for renewable power is likely to be strong with renewable capacity currently mainly being
used to displace high carbon generation on the grid (coal and gas power). Ultimately, the prioritisation
of the use of renewable power for different sectors will depend on various policy incentives. Figure 38
shows the current GHG emissions saved for the use of 1MWh of renewable electricity in different end
sectors for a country that relies on fossil fuel transport and natural gas heating (such as the Netherlands
or the UK). The ranking suggests other uses are likely to be currently prioritised over synthetic kerosene
as the supply of renewable power is still limited today. However, as the power sector, heating and light
duty road transport become progressively more decarbonised, this ranking will shift, and greater
attention will turn to decarbonising aviation through the use of synthetic kerosene routes. It should
also be noted that the use of synthetic kerosene in aviation could bring non-CO2 benefits (e.g. reduced
soot leading to improved air quality and reduced warming from cirrus cloud formation) which are the
subject of ongoing research, and are not factored into this analysis.
1
0.9
0.8
0.7

tCO2 eq saved

0.6
0.5
0.4
0.3
0.2
0.1
0

Displace coal
generation

Power on EV

Power a heat
pump

Displace gas
generation

Power DACCS Produce H2 for a
Produce
boiler
synthetic jet fuel

Figure 38: Current emissions saved by using 1MWh of zero carbon electricity26

One study estimates that replacing 50% of the EU’s aviation fuel demand in 2050 with renewable
synthetic kerosene would require a quarter of the EU’s current electricity generation27. While studies
vary in the predicted growth of synfuels they agree on the need to significantly increase the production
of renewable electricity to ensure additional renewable electricity is available over time to satisfy a
wider range of applications.

26 Climate Change Committee, ‘The sixth carbon budget: Electricity Generation’(2020), available at: https://www.theccc.org.uk/wp-

content/uploads/2020/12/Sector-summary-Electricity-generation.pdf
27 Cerulogy (2017) p.6, Available online:
https://www.transportenvironment.org/sites/te/files/publications/2017_11_Cerulogy_study_What_role_electrofuels_final_0.pdf

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Decarbonisation potential of synthetic kerosene

Carbon dioxide sources
The production of synthetic kerosene, except for routes which use recycled CO as discussed further
below, require a source of CO2. Approximately 4.15 tonnes of CO2 are required to produce one tonne
of synthetic fuel via the Fischer-Tropsch synthesis and 4.86 tonnes of CO2 via the methanol-to-jet
route28. The resulting CO2 demand for these routes for each of the modelled scenarios to 2030 is
presented in Table 7.
Table 7: Estimated CO 2 supply needed to meet green synthetic kerosene demands in 2030

Scenario

Europe fast growth
Europe slow growth
Global fast growth
Global slow growth

Estimated synthetic
kerosene production
(ktonnes jet/yr)
2030
670
310
900
560

Estimated CO2 demand
(ktonnes CO2/yr)

2900
1300
3800
2300

As discussed in section 2.3, CO2 can be supplied either from DAC or from point source capture at
industrial sites (CCU).
The rate of deployment of DAC systems is initially dependent on the number of technology
developers and their individual scale up capability (Table 8). Over time, factors such as the availability
of low-cost renewable electricity29 or heat inputs to DAC systems are likely to be more significant
determinants.

28 Based on internal E4tech calculations.
29 'CO2 DAC for effective CC mitigation based on RE', Breyer & Fasihi, Mitigation and Adaptation Strategies for Global Change volume 25,

43–65, 2020

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Decarbonisation potential of synthetic kerosene
Table 8: Current status of DAC technology developers and plants
Company

30

Plants

Largest
plant

Tech Type

Energy source

Future plans
Developing plant in US to
remove 1 MtCO2/year30Work
with Pale Blue Dot Energy on
UK commercial- scale DAC
plant31

Carbon
Engineering

1

1 t/day

HT aqueous
solution

Natural gas (CO2
is captured) and
renewable
power

Global
Thermostat

2+ (colocated w/
industrial
plants)

4000
t/year

LT solid
sorbent (TSA)

Waste heat
(electricity needs
not stated)

Partner with ExxonMobil to
scale up and remove 1 GtCO2/yr
and expand to 40 GtCO2/yr32 33

Climeworks

14

900
t/year

LT solid
sorbent (TSA)

Renewable
electricity or
waste heat

Project Orca to capture 4000
tCO2/year in Iceland.
3 more plants in planning or
production34

Airthena

1

6 kg
CO2/day

LT solid
sorbent (TSA)

Renewable
electricity

Planned field trials35

Hydrocell

1

3.8
kg/day

LT solid
sorbent (TSA)

Renewable
electricity (solar)

Carbyon

1

Bench

LT solid
sorbent (TSA)

Renewable
electricity

Infinitree

1

Bench

LT solid
sorbent
(MSA)

Unknown

Little information39

No energy for
capture but
unknown for
sorbent regen.,
compression etc

Deploy small-scale in 2021 to
capture 1-2 tCO2/day to expand
to 30 tCO2/day and eventually
4MtCO2/year40 41

Silicon
Kingdom
Holdings

1

Bench

LT solid
sorbent
(MSA)

Skytree

1

Bench

LT solid
sorbent
(MSA)

Waste heat

Prometheus
Fuels

1

20, 000
t/year43

Unknown

Renewable
electricity

Partner in the Soletair project
aiming for 100% renewable
consumer products36 37
Working with Dutch research
institutions to maximise
efficiency38

First product will be in airquality management in electric
vehicles42
Aim to sell fuel late 2021. Other
products for CO244 use in pipe

Carbon Engineering, 2020 https://carbonengineering.com/

31 Lammey, 2020 “UK’s first commercial-scale direct air capture plant to be based in north-east”

https://www.pressandjournal.co.uk/fp/business/north-of-scotland/2495944/uks-first-commercial-scale-direct-air-capture-plant-to-bebased-in-north-east/
32 Global Thermostat, 2020 https://globalthermostat.com/
33 Soltoff, 2019 “Inside ExxonMobil’s hookup with carbon removal venture Global Thermostat https://www.greenbiz.com/article/insideexxonmobils-hookup-carbon-removal-venture-global-thermostat
34 Climeworks, 2020 https://www.climeworks.com/
35 Sadiq et al, 2020 “A Pilot-Scale Demonstration of Mobile Direct Air Capture Using Metal-Organic Frameworks”
https://onlinelibrary.wiley.com/doi/10.1002/adsu.202000101
36 Hydrocell, 2020 https://hydrocell.fi/en/air-cleaners-carbon-dioxide-filters-and-dac-appliances/dac-appliances/
37 Bajamundi et al, 2019 “Capturing CO from air: Technical performance and process control improvement”
2
https://reader.elsevier.com/reader/sd/pii/S2212982018310187?token=4CE9DD02A585A69316300EBB2C0AD6C9066FBEBB34FD5574A8A9
05AAB0CFABAD4F2983C363454E6C30D63B2339B07E87
38 Carbyon, 2020 https://carbyon.com/
39 Infinitree, 2017 http://www.infinitreellc.com/
40 Ortega, 2020 “The world’s first mechanical tree prototype is to be built at ASU next year”
https://www.statepress.com/article/2020/10/spbiztech-the-worlds-first-mechanical-tree-is-to-be-built-at-asu-by-next-year#
41 Silicon Kingdom Holdings https://mechanicaltrees.com/
42 Skytree, 2020 https://www.skytree.eu/
43 Prometheus Fuels state that in a year their technology “turns 20 kilotons of atmospheric CO2 into one million gallons of gasoline, diesel,
or jet fuel” https://www.prometheusfuels.com/technology/
44 Prometheus Fuels, 2020 https://www.prometheusfuels.com/

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Decarbonisation potential of synthetic kerosene
Point source CO2, captured either from fossil or biogenic sources, presents an alternative to DAC
especially in the short term. Table 9 gives an overview of potential CO2 sources from a range of
industrial processes. Using point source CO2 to produce synthetic kerosene is lower cost than DAC and
presents lower technology risks, which could be important to proving synthetic kerosene production
at scale. However, the use of point source CO2 for synfuels introduces the risk of prolonging CO2
emissions from fossil sites and concerns over ‘lock-in’ to fossil sources or higher emissions technology.
Table 9: Classification of potential CO 2 sources including the typical CO 2 concentrations45
CO2 from
combustion
processes
Coal
12-15 vol.%
Natural Gas
12-15 vol.%
Oil
3-8 vol.%
Biomass
3-8 vol.%
Waste sources
12 vol. %

CO2 as by-product from industrial processes
Biotechnological
Chemical
Industrial
processes
Industry
Production
Biogas upgrading
Ethylene
Cement
40 vol.%
12 vol.%
20 vol.%
Bioethanol
Ammonia
Iron and Steel
Up to 100 vol.%
Up to 100 vol.%
15 vol.%
Fermentation
Refineries
Up to 100 vol.%
3-13 vol.%

CO2 from the
atmosphere
Ambient air
0.039 vol.%

The concentration of CO2 at the point of capture affects the cost and efficiency of the process and
sources that produce CO2 streams of over 95% purity are ideally placed to be ‘first-movers’ for
industrial CCU, as expensive separation of the CO2 is not required. Industries where such sources are
available include natural gas processing, bioethanol/biofuel plants (including biomethane upgrading
from biogas), ammonia production, ethylene oxide production and hydrogen production46. Fossil fuel
lock-in could be avoided by progressive fuel switching to biogenic sources in industrial processes.
A review of the literature on the availability of point source CO2 for synthetic fuels (including kerosene)
production47 suggests that sufficient CO2 is likely to be available to meet the demand of synthetic fuels
production (Table 10).
Table 10: European (EU 27 + UK)Potential CO 2 availability from concentrated sources, according to
different references analysed in the Concawe synfuels literature review48

References used

ICCT (2017)
LBST and dena (2017)
Dechema (2017)

Potential CO2availability from
concentrated sources (Mtonnes/yr)
2030
2040
896
680
165
165
952
516

45 Assessing the potential of CO2 valorisation in Europe – Rodin et al Journal of CO2 utilization 41, 2020, 101219
46 IEA Report ‘CCUS in clean energy transitions’, Available at: https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-

ccus#growing-ccus-momentum
47 Role of e-fuels in the European transport system - Literature review, Concawe (2020), available at: https://www.concawe.eu/wpcontent/uploads/Rpt_19-14.pdf
48 Role of e-fuels in the European transport system - Literature review, Concawe (2020), available at: https://www.concawe.eu/wpcontent/uploads/Rpt_19-14.pdf

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Decarbonisation potential of synthetic kerosene
While the use of concentrated carbon sources is expected to dominate synthetic kerosene production
in the short term, the continued use of fossil sources is incompatible with reaching carbon neutrality.
A progressive shift to DAC technologies or biogenic point sources is required in the longer term. In a
recent study Breyer et al (2020) have projected that CO2 demand for synfuels will initially be supplied
from concentrated sources, but will change to DAC over time (Figure 39)49. This assumes point source
CO2 is either biogenic or from sources of CO2 that are more difficult to eliminate (e.g. waste
incinerators, cement manufacture). Breyer et al project that by 2050, DAC will be an essential
technology for achieving net zero emissions with 80% of all CO2 raw material provided by DAC and the
remaining demand covered by point sources (Figure 39)50.

Figure 39: CO2 supply for SNG, synfuels and methanol synthesis in Europe 51

Natural Gas
The blue synthetic kerosene routes rely on hydrogen derived from natural gas reforming. The CO 2
emissions generated during the process are captured via dedicated carbon capture and storage (CCS)
facilities. The distribution infrastructure is widely established at a global scale further suggesting that
the supply of natural gas will not limit the growth of blue synthetic kerosene routes. The most
important bottleneck in the scale-up of blue hydrogen based synthetic kerosene routes is likely to be
the rate at which CCS facilities can be deployed.
CSS technologies have been identified as an important factor to reach the climate goals outlined by
the Intergovernmental Panel on Climate Change (IPCC). Many scenarios developed require over 1000
gigatons of CO2 stored underground by the end of the century, yet the availably of underground CO2
storage capacity is still highly uncertain52. In Europe, the realisation of large-scale CCS projects has
been quite challenging with many projects being put on hold or even cancelled53. The utilisation of CCS
was mainly driven for use for enhanced oil recovery, this, however, is unlikely to be sufficient to
support the growth in CCS technologies needed to reach the net zero targets54.

49 Powerfuels in a Renewable Energy World Study presentation Breyer and Crane 2020
50Powerfuels in a Renewable Energy World Study presentation Breyer and Crane 2020
51 Powerfuels in a Renewable Energy World Study presentation Breyer and Crane 2020
52 Zahasky C, Krevor S. Global geologic carbon storage requirements of climate change mitigation scenarios. Energy & Environmental

Science. 2020;13(6):1561-1567.
53 EU Science Hub, Available at : https://ec.europa.eu/jrc/en/research-topic/carbon-capture-utilisation-and-storage
54 IEA Report ‘CCUS in clean energy transitions’, Available at: https://webstore.iea.org/download/direct/

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Decarbonisation potential of synthetic kerosene
Additional policies and financial mechanisms may be required to incentivise the CCS from power
generation to other industries and thereby to allow the sustainable growth of CCS technologies55.
An advantage of CO2 capture technologies is that they can be retrofitted and added to existing
industrial plants. This is especially interesting for relatively new industrial facilities which could remain
operational for the next decades. For example, on average a European fossil-based plant remains
operational for 35 years (this applies to coal-fired plants)while the emissions associated with industrial
plants depend on the subsector (cement, chemical etc) 56 . Ways to reduce the emissions include
retrofitting these facilities with CCS technologies or shut down the plants early.
While the cost of electrolysis-based hydrogen is predicted to decrease in the coming years, CCS could
present a good opportunity to address the GHG emissions of existing hydrogen production plants,
accounting for 800 MtCO2/year today57. Post 2030, this assessment assumes growth in blue hydrogen
production facilities (either new build reformers with CCS or retrofitting of CCS to existing SMRs) of
11% a year. This number is based on the global capacity of CO2 capture from large scale natural gas
facilities of 9.2Mt in 2019 to 26.9 Mt in 203058.

Intermediate feedstock
The methanol-to-jet and CO fermentation to jet routes rely on methanol and ethanol, with their scale
up potentials modelled as “intermediates” in this assessment. Methanol can be produced via
renewable power-to-methanol or blue methanol routes, while in the scope of this study ethanol is
produced via the fermentation of steel mill waste gases. In the short term, the ramp up of these
intermediates has been estimated using the same modelling approach adopted for the jet synthesis
routes (see section 3.2.2).
LanzaTech is the only technology developer fermenting fossil off-gases into ethanol which explains the
low scale up of this route. The availability of steel mill off-gas will be discussed in a dedicated section
below. The large-scale production of CO based ethanol is a prerequisite for the large-scale capacity
potential of the CO based jet synthesis. For this reason, the ramp up of CO-based ethanol will limit the
scale up potential of the entire route to jet.
The model predicts strong scale up potential for methanol in 2050 (Figure 40), based on a large
number of developers with currently smaller-scale facilities. To date the number of methanol-to-jet
initiatives is very limited, projects for low carbon methanol on the other hand are relatively abundant.
In particular renewable power-to-methanol benefits from strong activity in the wider power-to-liquids
sector. Project consortia are generally led by players from various industries, in some cases including
airlines. To date, there are no blue methanol development projects, for this reason the potential of
blue methanol as intermediate feedstock was not modelled in this assessment. Methanol is a versatile
chemical with applications in many industries including the chemical sector, road transportation and
the shipping industry. This suggests potential competition for intermediate methanol between
different end sectors, however, analysis of this competition is out of the scope of this study.

55 EU Science Hub, Available at : https://ec.europa.eu/jrc/en/research-topic/carbon-capture-utilisation-and-storage
56 IEA Report ‘CCUS in clean energy transitions’, Available at: https://webstore.iea.org/download/direct/4191
57 IEA Report ‘CCUS in clean energy transitions’, Available at: https://webstore.iea.org/download/direct/4191
58 57

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Decarbonisation potential of synthetic kerosene

CO based ethanol Slow Growth

PtL Methanol Slow Growth"

CO based ethanol Fast Growth

PtL: Methanol Fast Growth

175

Jet fuel [ Mtonnes / year ]

140

105

70

35

Figure 40: Europe, capacity scale up of “intermediates” to 2050 for all scenarios. (CO based ethanol
refers to the Steel mill gas fermentation to ethanol route)

Steel mill off gas availability
Steel mill waste gas streams represent a potential resource for fermentation into low carbon ethanol
or for FT synthesis into jet. As introduced above offgas from steel industries represents a significant
source of GHG emissions and integrated steel mills are therefore a good candidate for point source
carbon capture59. The largest single point source at a steel mill is the blast furnace, from which 65% of
the emissions can be captured. Blast furnace gas (BFG) can be used for electricity production in some
integrated plants, or as a feedstock for bio-ethanol (STEELANOL project) or ammonia or methanol
(Carbon2Chem project), so if the CO from BFG is to be used for synfuel synthesis it should be confirmed
that this gives the greatest lifecycle GHG benefit.
Today the availability of sources of CO from industrial processes are fairly widespread, however these
may not be as geographically dispersed as CO2 sources. This could potentially limit the locations where
this technology could be used. According to Lanzatech, the current availability of steel mill emissions
is estimated to equate to 110 billion litres of ethanol annually 60 , which could produce 50
Mtonnes/year61 of jet. While quantities of CO are not limited today these could be expected to reduce
over time unless the CO is sourced from other feedstocks such as from biogenic sources. However, the
IEA also estimates that over 40% currently operational steel manufacturing assets could still be
operational in 205062.

59 Leeson et al. ‘A Techno-economic analysis and systematic review of CCS’. International Journal of Greenhouse Gas Control, Volume 61,

2017, Pages 71-84
60 LanzaTech (2017), Available at: https://www.energy.gov/sites/prod/files/2017/07/f35/BETO_2017WTE-Workshop_SeanSimpsonLanzaTech.pdf
61 Calculated from 30bn gallons of EtOH from steel mill waste gas, assuming a conversion yield (MJ fuel/MJ ethanol) of 91%.
62 IEA Report ‘CCUS in clean energy transitions’, Available at: https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-forccus#growing-ccus-momentum

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Decarbonisation potential of synthetic kerosene
The CO to jet routes (routes 13-15) represent an option to recycle waste gas streams into useful end
products, instead of generating power. Overall, between 59 and 98 Mtonnes/year of input CO63 would
be required to meet the jet fuel capacity as estimated in the ramp up scenarios in 2050, i.e. between
7 and 13 Mtonnes/yr. This suggests that the availability of CO sources is unlikely to limit the scale up
of CO-based jet routes. However, as discussed above, the ramp up model assumes the limited number
of technology developers involved in these conversion technologies to represent the major bottleneck
for the scale up of the CO to jet routes. This means that the methodology applied could underestimate
the supply of jet fuel via CO sources.

Water considerations
Water could also be considered as a resource subject to availability constraints, given its input into the
production of synthetic kerosene. The net water demand can be estimated from the amount needed
for electrolysis or gas reforming as well as from water required and/or generated in further
downstream processing steps. The theoretical minimum amount of water required is approximately
1.3 to 1.4 litres of water per litre of jet fuel64, but will be higher in reality given the actual performance
of the conversion technologies and heating/cooling equipment applied.
Local water availability could therefore become an issue if water supplies in specific locations are
already under stress65, but will need be considered on a case-by-case basis when setting up a new
hydrogen production or synthetic kerosene plants. However, the water consumption for synthetic
kerosene production is negligible compared to biofuels routes.66

4.2.4 Certified supply routes and routes in certification process
There are currently 8 ASTM certified production routes for SAF, with a number of other routes in the
certification process and several other routes that are not in the certification process yet, but that
could reach approval by 2030. The technical and commercial status of all these routes is presented
and summarised in Table 11.

63 The amount of CO required was calculated according to the following ratio: for the CO fermentation to jet route, 6.3 tonnes of CO for 1

tonne of jet fuel and for the CO + FT route 8 tonnes of CO for 1 tonne of jet fuel, multiplied by the predicted volume of CO fermentation to
jet estimated for all growth scenarios.
64 Power-tp-Liquids Potentials and Perspectives for the Future Supply of Renewable Aviation Fuel (2016), Available at:
https://www.umweltbundesamt.de/publikationen/power-to-liquids-potentials-perspectives-for-the
65 Schmidt and Weindorf report a carbon number distribution between 8 and 16 (8–16 carbon atoms per molecule) for jet fuel, Power-toLiquids Potentials and Perspectives for the Future Supply of Renewable Aviation Fuel (2016), available at:
http://www.lbst.de/news/2016_docs/161005_uba_hintergrund_ptl_barrierrefrei.pdf
66 For biofuels a factor of 400 to 15,000 more water needed compared to power-to-liquids production from renewable electricity, Powerto-Liquids Potentials and Perspectives for the Future Supply of Renewable Aviation Fuel (2016), available at:
http://www.lbst.de/news/2016_docs/161005_uba_hintergrund_ptl_barrierrefrei.pdf

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Decarbonisation potential of synthetic kerosene
Table 11: Summary of SAF routes development status

Route

Certification67

Technology status

Global volumes of
jet fuel produced in
2018 (kt/y)

Hydroprocessing oils/fats

HEFA-SPK up to
50% blend

Commercial (TRL 8)

17

CHJ

TRL to be confirmed

No commercial
production

HC-HEFA-SPK,
up to 10% blend

TRL to be confirmed

No commercial
production

Commercial (TRL 8-9)

No commercial
production

Catalytic Hydro-thermolysis
Synthesized Kerosene
Hydro-processed
hydrocarbons, esters and
fatty acids
Co-processing oils/fats
Alcohols to Jet

D1655, up to 5%
co-feed
ATJ-SPK up to
50% blend

Demonstration (TRL 6-7) 0.3
Demonstration (TRL 6
for biogenic routes) or
commercial (TRL 8-9 for
fossil routes)
Demonstration (TRL 6
for biogenic routes) or
commercial (TRL 8-9 for
fossil routes)
Prototype (TRL 5) for
lignocellulosic sugars,
pre-commercial (TRL 7)
for conventional sugars

Fischer-Tropsch

FT-SPK up to
50% blend

No commercial
production

Fischer-Tropsch with
Aromatics

FT-SPK/A up to
50% blend

Hydroprocessed fermented
sugars to synthetic
isoparaffins

HFS-SIP up to
10% blend

IH2 Pyrolysis + upgrading

Ongoinga

Demonstration (TRL 6)

No commercial
production

Hydro-deoxygenation
Synthetic Aromatic
Kerosene

Ongoing (HDOSAK)

Prototype (TRL 4-5) for
lignocellulosic sugars,
demonstration (TRL 5-6)
for conventional sugars

No commercial
production

Hydrothermal liquefaction

Pre-qualification
stage

Demonstration (TRL 5-6)

Hydroprocessed
Depolymerized Cellulosic Jet

Pre-qualification

TRL to be confirmed

No commercial
production

No commercial
production

No commercial
production
No commercial
production

a) IH2 catalytic process developed by Shell is undergoing certification
b) PtL FT jet fuel can be certified as FT-SPK as long as the FT synthesis is based on iron or cobalt catalysts68

Hydroprocessing of oils and fats (HEFA)
Hydroprocessing of oils and fats is the most mature SAF route and the fuel produced through this route
is certified for use by ASTM as HEFA-SPK in blends of up to 50%. The production process is the same as
for Hydrotreated Vegetable Oil (HVO) but it uses a narrower hydrocarbon cut and includes an more
severe isomerisation step that lowers the fuel freezing point. HEFA is the only type of SAF commercially
used today dependence on waste or vegetable oil feedstocks could limit its availability over time. To
67 CAAFI, Fuel qualification – Current status, accessed on Oct 2019, http://www.caafi.org/focus_areas/fuel_qualification.html
68 D7566 specification, Annex1, article A1.4.1.1

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Decarbonisation potential of synthetic kerosene
reflect sustainability concerns, biofuels from waste oils and vegetable oils have limits to their
contribution towards RED II targets but a variety of alternative crops are being investigated in terms
of potential and sustainability. Larger volumes of HEFA SAF could potentially be supplied if High Freeze
Point HEFA (HFP-HEFA) was approved as an aviation fuel. Given the similarity of HFP-HEFA to diesel
HVO, approval would mean HVO capacity could, in principle, be quickly converted to HEFA provided
market drivers were sufficiently strong.

Catalytic Hydrothermolysis Synthesized Kerosene (CHJ)
CHJ is a recent addition to ASTM D7566 Annexes and was officially approved in January 2020 with
maximum blending of 50%. The CHJ process (based on hydrothermal liquefaction technology) consists
of three main steps. In the first step clean free fatty acid (FFA) oil from the processing of waste oils is
converted into a bio-crude oil inside the catalytic hydrothermolysis reactor. In the second step, the
bio-crude oil undergoes hydrotreating and is converted into a mixture of several different
hydrocarbons. Finally, this mixture is separated through distillation into single fractions (diesel, jet,
gasoline). Research has shown that through the CH process, SAF can be produced from a variety of
triglyceride-based feedstocks such as soybean oil, jatropha oil, camelina oil, carinata oil, and tung oil69.
Because the CH process uses waste or virgin vegetable oils, it faces similar challenges as the HEFA/HVO
route regarding feedstock availability and sustainability. Additionally, the technology is still at an early
stage and the fuel production cost is high relative to fossil jet70.

Hydrocarbon-hydroprocessed Esters and Fatty acids (HC-HEFA-SPK)
HC-HEFA-SPK is the latest fuel addition to ASTM D7566 Annexes, approved in May 202071. This is a
HEFA-type fuel derived from micro-algae. The process to produce HC-HEFA-SPK is identical to the
standard HEFA-SPK with the addition of a pre-treatment step. Micro-algae containing oils are first
dried, and then the oil content is extracted using a solvent. The oil extracted then undergoes
hydrotreating as in the standard HEFA process. IHI Corporation is developing this route based on a
specific type of micro-algae called “Botryococcus braunii”. This species of micro-algae is particularly
suitable for fuel production because it offers high oil yields compared to other types of feedstocks. The
main challenges associated with micro-algae cultivation are the long-term stability and productivity of
the crop, the overall process economics, and GHG emissions. Cultivation of micro-algae has relatively
high energy consumption and associated GHG emissions if that energy is based on fossil sources.

Co-processed oils and fats
SAF can also be produced through co-processing oils and fats at refineries with the advantage of
exploiting existing facilities and fuel distribution networks. Typical percentages of co-feed are between
5% and 10% of the total feedstock, although up to 30% co-processing has been achieved in some
circumstances. Co-processing vegetable oils may require some equipment and plant set-up
modifications, which are minimal below 5% but can become significant above this threshold72. The
ASTM conventional jet fuel standard (D1655) limits co-processing of renewable lipids to 5%.

69 https://www.greencarcongress.com/2020/02/2020-0201-astmchj.html
70 Table A5, p99, https://www.nrel.gov/docs/fy16osti/66291.pdf
71 Green Car Congress, May 2020, https://www.greencarcongress.com/2020/05/20200514-ihi.html
72 Concawe, 2019, “Refinery 2050: Conceptual Assessment”, PDF page 32, https://www.concawe.eu/wp-content/uploads/Rpt_19-9.pdf

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Decarbonisation potential of synthetic kerosene

Alcohol to Jet (AtJ)
Alcohols produced through fermentation of sugar or starch crops or through advanced routes from
lignocellulosic feedstocks, such as woody and grassy feedstocks, and wastes can also be catalysed to
produce jet fuel. ASTM first certified ATJ-SPK bioblends up to 50%v/v in 2016. AtJ offers logistical
flexibility because the alcohol catalysis plant does not need to be co-located with alcohol production,
and alcohols can be conveniently transported and stored. Competition from direct use of alcohols in
transport applications (e.g. road and marine), as opposed to converting them to jet fuel, is likely to be
strong given the additional capital expenditure, efficiency loss associated with jet fuel production. The
AtJ approach is being expanded through the addition of Alcohol to Jet Synthetic Kerosene with
Aromatics (ATJ-SKA) which is similar to ATJ-SPK but contains a higher amount of aromatic compounds,
which ensure the swelling of seals in current jet engines. ATJ-SKA, if approved, has the potential to be
directly used in aircrafts without blending and the fuel is in Phase 1 – Testing of the ASTM certification
process. Other variants in development include “Consolidated Dehydration and Oligomerisation”
(CADO) which does not require the additional hydrogenation step typically present in the back end of
more established ATJ routes.

Fischer-Tropsch synthesis (FT-SPK and FT-SPK/A)
All jet fuel produced by Fischer-Tropsch synthesis is ASTM qualified, regardless of the syngas feedstock
(whether biogenic, fossil or atmospheric carbon). Jet fuel produced through gasification + FT (FT-SPK)
was the first route to be certified in 2009 and can be blended with fossil kerosene up to 50%. While
commercially mature for coal and natural gas-to-liquid routes, the bio-based route faces the challenge
of scaling down FT synthesis and hydrocracking equipment to capacity levels suitable for biomass and
waste-based gasification systems. One option for improving the economics could be co-process the
intermediate FT waxes at existing oil refineries, rather than upgrading them in a dedicated
hydroprocessing plant. This alternative refinery co-processing route has been certified by ASTM at up
to 5% by volume.

Direct sugars to hydrocarbons (DSHC)
DSHC routes use genetically modified microorganisms to convert sugars into hydrocarbons or lipids.
Three main routes are under development whose products can be further processed into jet fuel:
heterotrophic algae or yeast converting sugars into lipids within their cells; genetically modified yeasts
which consume sugars and excrete long-chain liquid alkenes (e.g. farnesene); genetically modified
bacteria consuming sugars and excreting short-chain gaseous alkenes (e.g. isobutene). These currently
use conventional sugar feedstocks, although pilot projects are testing cellulosic sugars. One specific
route based on the production of farnesene from sugar is ASTM certified (HFS-SIP) and can be blended
with fossil kerosene up to a maximum of 10%. The complexity and low efficiency results in high
feedstock cost and high energy consumption, making DSHC an expensive SAF route.

Pyrolysis and upgrading
Pyrolysis can be used to transform lignocellulosic biomass or solid waste into an intermediate biocrude oil, which can then be upgraded to aviation fuel. KiOR had embarked on ASTM certification of
bio-kerosene from fast pyrolysis, before filing for bankruptcy but now Shell is in Testing Phase 1 of
ASTM D4054 for its catalytic pyrolysis process (IH2). There is no commercial process for upgrading
pyrolysis oil to finished fuel in dedicated plants but research into materials and catalysts is ongoing.
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Decarbonisation potential of synthetic kerosene

Aqueous Phase Reforming (APR)
The APR process catalytically converts biomass-derived oxygenates (such as sugars, sugar alcohols and
polyols) into a hydrocarbon mixture that can be separated into a fuel slate including kerosene. Aviation
kerosene produced via APR is in Phase 2 of the ASTM certification procedure (HDO-SAK). Unlike other
reforming processes, APR operates in wet conditions which reduces the costs of dewatering certain
feedstocks like sugars. However, it has low selectivity to liquid hydrocarbons (high gaseous yields) and
short catalyst lifetime, making APR expensive today.

4.2.5 Summary of Pre-Qualification Stage routes
Several companies and organisations are engaging with ASTM but have not yet embarked on the
certification process as shown in Figure 41. Some of these companies have already reached out to
CAAFI and OEMs to begin the certification process.

Figure 41: ASTM pipeline of routes yet to enter qualification 73

These pre-qualification stage routes have been grouped by type of feedstock and are discussed further
in the sections below.

Hydrothermal Liquefaction (HTL)
HTL involves heating biomass and water at very high pressures to produce a bio-crude, with the
near/super-critical water acting as a reactant and catalyst to depolymerise the biomass. The bio-crude
produced can then be upgraded and while the higher molecular weight distribution makes HTL oil
more suitable for diesel production, gasoline and jet are possible adding hydrocracking steps. HTL is
well suited to very wet biomass feedstocks (sewage sludge, manure, micro and macro algae), as well
as some lignocellulosic feedstocks. This route has not entered the ASTM certification process.

73 https://www.gti.energy/wp-content/uploads/2019/10/47-tcbiomass2019-Presentation-Steve-Csonka.pdf

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Decarbonisation potential of synthetic kerosene

Hydroprocessed Depolymerized Cellulosic Jet (HDCJ)
Hydroprocessed Depolymerized Cellulosic Jet (HDCJ) is a class of processes that includes different
routes converting lignocellulosic feedstocks into liquid fuels via thermochemical reactions. Most of
these routes involve some form of pyrolysis.

Other routes
Global Bioenergies is pursuing a biological route to SAF production based on genetically modified
bacteria converting sugars into isobutene producing a type of fuel similar to HFS-SIP. The technology
maturity using conventional sugar feedstocks is at TRL 7-8, while the same processes based on
cellulosic feedstocks is at TRL 5.
Another promising route to create renewable jet fuel is the Lipid-to-Hydrocarbon (LTH) technology. It
converts waste fats and other organic oils into hydrocarbons. This conversion is performed through a
two-stage process, hydrolysis followed by pyrolysis74, and does not require any catalyst or hydrogen.
Several developers are looking at these routes including Forge Hydrocarbons and SBI Bioenergy
MSW can be converted into jet fuel via gasification combined with methanol/DME synthesis and this
is being investigated in the UK through the WasteWindWing (WWW) project. University College
London are currently conducting a FEED study as the basis for a pilot plant to be built by 2022. ABSL
are the expected gasification technology supplier75.
Mercurius Biorefining, a US company, is developing a novel process which converts cellulosic biomass
to renewable diesel, aviation and marine fuels. Their technology, “REnewable Acid-hydrolysis
Condensation Hydrotreating” (REACH), creates an intermediate bio-crude product through the use of
catalytic hydrolysis, which is then upgraded to transport fuel through commercial hydrotreating
equipment76.
Elsewhere, Anellotech’s patented Bio-TCat™ process produces 100% bio-based aromatic chemicals
(i.e. benzene, toluene and xylene) which can be used as bio-marine fuel, or can be upgraded to make
diesel or jet fuel blendstocks77.

4.2.6 Current and future costs of biomass SAF routes
The cost of selected advanced biojet production is shown in Figure 42. The data used is mainly from
an IRENA review of advanced biofuel routes, supplemented with additional sources where data was
not available, and compared with other sources. All the routes are more expensive than fossil kerosene
price (€600 /t pre-COVID78). Producing jet from a first of a kind (FOAK) plant can cost between €740
and 6,500 /t depending on technology, plant scale and type of feedstock.

74 Green Car Congress, October 2013 : https://www.greencarcongress.com/2013/10/20131014-forge.html
75 IATA, 2019, “Sustainable Aviation Fuel Symposium”,

https://www.iata.org/contentassets/8dc7f9f4c38247ae8f007998295a37d5/safs2019-day1.pdf
76 Mercurius Biorefining website, accessed on 12/05/2020, https://www.mercuriusbiofuels.com/Technology.html
77 Anellotech website, accessed on 12/05/2020, https://www.anellotech.com/about-us
78 OPIS, 2019, OPIS Europe jet, diesel & gasoline report, https://www.opisnet.com/wp-content/uploads/2019/01/europe-jet-reportsample.pdf

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Decarbonisation potential of synthetic kerosene

Figure 42: Fuel production cost for advanced biofuel routes. Source: multiple 79

Hydroprocessing of oils and fats is the most mature SAF technology, and is also currently the lowest
cost route for SAF production. HEFA jet production costs can vary from 740 to 860 €/tonne where the
lower end corresponds to a large scale plant and the upper end to a small scale plant. The most
expensive route is Direct Sugars to Hydrocarbons reflecting the fact that transforming lignocellulosic
biomass to sugars to intermediate products before upgrading remains a low efficiency route.
Despite the high cost of FOAK plants, technology learning can drive down capital cost and deliver
operational learning. For several routes there are also large economies of scale. As a result, NOAK
plants are in general less expensive than FOAK for all routes. In some cases, up to 60% reduction on
production cost are expected when producing fuel from a NOAK plant. However, as Figure 42 shows,
this cost reduction alone is not projected to make SAF cost-competitive with fossil kerosene. Either
incentives for SAF or carbon taxes on fossil fuels are required to close this cost gap.

4.2.7 Cost of GHG saving of biomass SAF routes
The costs of GHG saving for the different SAF routes are shown in Figure 43. This is calculated as the
cost difference between SAF and fossil jet divided by the SAF GHG emission savings. The overall picture
for GHG saving cost is similar to the fuel production cost. The more mature technologies such as
hydroprocessing of waste oils/fats and gasification of waste wood + FT are the most cost-effective
decarbonisation options, while DSHC is significantly more expensive. The lowest GHG saving cost is
€62/tCO2e for hydroprocessing of waste oils/fats, while the highest is €1,960/tCO2e for a FOAK DSHC

79 IRENA, 2016, Innovation Outlook: Advanced Liquid Biofuels, https://www.irena.org/publications/2016/Oct/Innovation-Outlook-

Advanced-Liquid-Biofuels; De Jong et al., 2015, The feasibility of short-term production…,
https://onlinelibrary.wiley.com/doi/abs/10.1002/bbb.1613; NREL, 2016, Review of biojet fuel conversion technologies,
https://www.nrel.gov/docs/fy16osti/66291.pdf; Malins, 2017, What role is there for electrofuel…,
https://www.transportenvironment.org/sites/te/files/publications/2017_11_Cerulogy_study_What_role_electrofuels_final_0.pdf

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Decarbonisation potential of synthetic kerosene
case. However, it is important to note that the results are highly dependent on the feedstocks used, in
particular for oil feedstocks.

Figure 43: Carbon saving cost for advanced biofuel routes. Source: E4tech analysis based on multiple
sources80

80 See Figure 42

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5 Conclusions and implications
Current costs are high for green routes, whereas blue routes offer a lower cost alternative today
Our analysis shows that estimated costs of green synthetic jet fuel today (routes 1-6) would likely be
very high, ranging from €4300 - 6800/tonne compared with pre-COVID fossil jet prices of around
€600/tonne (assuming no carbon price is applied to fossil fuels). Costs for the methanol to jet and FT
routes are very similar, since the majority of the production cost is hydrogen, and both routes have
very similar hydrogen requirements. However, FT routes are ASTM approved and are more
commercially mature than methanol to jet routes, which are yet to be ASTM certified.
Blue routes (routes 7-12, where blue hydrogen is combined with CO2) currently have a cost advantage
over green routes, due to the lower cost hydrogen, but the cost of blue synthetic kerosene at €1,5002,300/tonne is still significantly higher than the price of conventional fossil jet (ignoring carbon pricing).
Note that routes using waste CO (routes 13-15) could be more competitive, as discussed below.
The most costly routes are those involving DAC (routes 3, 6, 9 and 12), which is still to be
commercialised, and requires significant energy inputs (which could be renewable as in DAC2, or
supplied from power and gas grids as in DAC1). It is anticipated that the cost of DAC will fall
considerably over time, reflecting learning rates, industrialisation of production and economies of
scale. A faster ramp-up could accelerate these cost reductions.
Improving efficiencies and falling renewable power generation prices will see cost of green and blue
routes converge by 2050
While blue synthetic kerosene is shown to be cheaper than green today, a combination of factors are
expected to mean that costs converge over time. In 2050, the cost of green routes varies between
€1,500 – 2,000/tonne while blue routes are in the range €1,300 – 1,700/tonne. The biggest factor is
the expected fall in renewable electricity costs, although improving electrolyser efficiencies and falling
capital costs across the process chain as scales increase also play a role. However, rising natural gas
costs also contribute to the convergence in costs, by limiting blue route cost reductions. This
convergence could facilitate a transition from blue to green routes over time, especially as the
imposition of any carbon price on fossil fuels would tend to reduce the competitiveness of blue routes
relative to green.
However, even after costs reductions, in 2050 the cost of synthetic kerosene remains significantly
above the price of fossil jet today, implying that there would be continue to be a need to support
synthetic kerosene routes, or to impose a carbon price on fossil fuels (assuming fossil jet prices were
not to rise significantly over time).
The GHG savings from blue routes are modest
While synthetic kerosene produced from blue hydrogen + CO2 is likely to be less costly than fuel
produced from green hydrogen today, it delivers only limited GHG savings. If synthetic kerosene based
on blue hydrogen + CO2 is deemed to have acceptable GHG savings and is adopted as an interim
solution, it will be important to consider how this can transition from blue to green hydrogen over time
in order to achieve Net Zero targets. Alternatively, blue hydrogen + CO2 routes could be deemed to
have insufficient GHG savings, and so might not be supported in policy.

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Decarbonisation potential of synthetic kerosene
Synthetic kerosene from blue hydrogen + CO2 from DAC may actually lead to an increase in GHG
emissions depending on the assumptions made about the source of heat energy for the DAC process
(in this analysis, assumed to be high temperature DAC fuelled by natural gas). Emissions from blue
hydrogen + CO2 routes (routes 7-12) are in the range 50-113 gCO2e/MJLHV today falling to 49-81
gCO2e/MJLHV in 2050 (the REDII transport fossil fuel benchmark is 94 gCO2e/MJLHV), with the routes
employing biogenic point source CO2 being the most attractive. This compares with 1-22 gCO2e/MJLHV
for the green hydrogen + CO2 routes (routes 1-6), although it is important to note the differences in
underlying assumptions for DAC heating used in the blue and green routes. It should also be noted that
biogenic point sources of CO2 are likely to have limited availability and it is expected that the availability
of fossil point sources of CO2 will also decline over time due to policy.
GHG abatement costs are high initially but come into line with biofuel SAF routes over time
Both the green and blue synthetic routes have high GHG abatement costs today, reflecting the high
costs of the green routes and the relatively poor GHG performance of the blue hydrogen + CO2 routes.
GHG abatement costs today are in the range €1,000 – 1,500/tCO2e for green routes and €500 900/tCO2e for blue (see Figure 26), which potentially supports the argument for allowing parallel
development of blue and green routes. By 2050, green routes are expected to have lower abatement
costs than blue routes, given falling costs. The CO based routes can have lower GHG abatement costs
than the CO2 routes, but only if the counterfactual use of the feedstock is unabated.
By 2050, synthetic kerosene is expected to have GHG abatement costs in a similar range to other forms
of SAF such as advanced biofuel routes (see Figure 43).
Routes which utilise CO rather than CO2 could provide a relatively low cost option and GHG emissions
savings for sites where waste CO is available and unabated
The use of recycled waste fossil (or biogenic) CO in the production of synthetic kerosene via FischerTropsch has potential, as the reverse water gas shift reaction required for CO2 routes can be avoided,
thereby resulting in lower costs and GHG emissions in 2030. Fuel costs of around €1,000 –
1,300/tonne in 2030 could be achievable with associated emissions highly dependent on the
feedstock counterfactual used. For example, for the CO + WGS route in 2030, synthetic kerosene net
lifecycle GHG emissions of -137 gCO2e/MJLHV (i.e. a very large GHG saving) could be achieved if the
feedstock counterfactual is unabated power generation (see Figure 24), but emissions would be 75
gCO2e/MJLHV if the counterfactual is abated power generation (see Figure 25). The equivalent figures
for CO + blue H2 are 27 gCO2e/MJLHV and 96 gCO2e/MJLHV, and for the CO fermentation + ATJ route
they are 32 gCO2e/MJLHV and 190 gCO2e/MJLHV respectively in 2030 (see Figures 22 and 23).
While there are a number of large point sources of recycled fossil CO available from industrial
processes today, these may not be as geographically dispersed as CO2 sources, potentially limiting the
locations where this technology could be used. Fossil CO volumes are not limited today, but could be
expected to reduce in availability over time as processes such as steel production decarbonise (e.g.
switching from coking coal to technologies such as direct reduced iron). Since the FT process is
indifferent to the source of syngas, CO based plants could transition from fossil CO to biogenic CO or
from blue to green hydrogen, or with some further investment, transition to use of CO2 (although this
has not been analysed in this study).

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Decarbonisation potential of synthetic kerosene

Methanol based routes show similar cost and GHG performance to FT alternatives
A full set of methanol to jet routes was explored using either green or blue hydrogen and the complete
range of CO2 sources. The cost and GHG performance of these routes was almost identical to the
results obtained for the FT routes. We conclude that any preference for one approach over the other
would be driven by operational considerations rather than cost or carbon reduction potential. For
example, methanol can be used as a fuel directly, as an input to other fuels including synthetic
kerosene and as an intermediate input to products such as plastics; this market flexibility may be
considered an advantage by some producers and may allow economies of scale to be realised.
Capacity scale-up could be rapid and make a contribution to the Netherlands’ SAF objectives
The capacity build up modelling carried out for this study suggests that supply could reach 966
ktonnes/yr in Europe by 2030, and 28 Million tonnes/yr by 2050 if the majority of global activity were
to remain in Europe. At global scale, the synthetic kerosene deployment could reach 1.3 Million
tonnes/year in 2030 and 37 Million tonnes/year by 2050. For comparison, in the International Energy
Agency’s (IEA) B2DS scenario81, which aims to achieve global net-zero emissions by 2060, global SAF
demand in 2060 reaches 150 Mtonnes/year corresponding to 70% of total aviation fuel demand.
Synthetic kerosene routes could therefore materially contribute to overall SAF supplies.
A review of feedstock availability suggests that based on this capacity build up feedstocks potentials,
at an aggregate level, are unlikely to restrict the rate at which capacity of any the routes considered
can be rolled out. However, specific local constraints (e.g. on carbon sequestration or supply of
renewable electricity) could affect the speed of roll out.
Whilst transitions or energy system modelling have not been examined in this study, an approach to
developing synthetic kerosene that allows the use of both green and blue routes could potentially
accelerate scaling up of the whole synthetic kerosene industry by introducing lower cost SAF earlier,
with blue shifting to green hydrogen supplies over time – although blue routes may have to meet
certain GHG savings thresholds to be deemed acceptable. Blue hydrogen production at scale would be
consistent with the optimal scale for fuel synthesis, but is dependent on CCS infrastructure. Green
routes, while currently significantly more expensive, do not necessarily rely on CCS infrastructure, will
benefit from rapidly decreasing renewable power costs, and could contribute to balancing increasing
renewable power on the grid.
Given asset lifetimes and the limited time available to 2050, there are also infrastructure lock-in risks
from large-scale blue hydrogen deployment to consider (along with the associated upstream fossil gas
supplies). If blue routes are to play only a transitional role given the modest GHG savings on offer, as
noted previously, transition pathways need to be identified. Similarly, recycled fossil CO sources could
be utilised for jet fuel production in the near to mid-term, but the need to avoid fossil emissions means
that steel mills will increasingly decarbonise towards 2050, limiting the availability of these routes, and
requiring switching of the jet synthesis plant to other feedstocks (either biogenic CO, or green
hydrogen, or non-fossil CO2 sources).
81 In the B2DS scenario “technology improvements and deployment are pushed to their maximum practicable limits across the energy

system in order to achieve net-zero emissions by 2060 and to stay net zero or below thereafter, without requiring unforeseen technology
breakthroughs or limiting economic growth”.

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Decarbonisation potential of synthetic kerosene
Further possible areas of investigation include a more detailed analysis of Net Zero compatible
pathways and assessment of alternative electrolysis routes
A valuable area of further investigation would be around Net Zero compatible transition pathways,
and how quickly the sector will have to transition from the use of point fossil sources of CO2 and/or
blue hydrogen to routes that use DAC or biogenic CO2 in conjunction with green hydrogen. This should
include consideration of the relative merits of different routes, including both FT and methanol
options. A more structured pathway analysis including timeframes, phase out/phase in transitions and
total cumulative GHG savings would be useful in developing a roadmap for the development of
synthetic kerosene.
A number of additional technologies are under development or consideration which have not been
considered in this analysis, e.g. high temperature solid oxide electrolysis and CO2 co-electrolysis, and
these could be explored in more detail. Some of these technologies offer promise, e.g. in terms of
improved efficiency, so support for their research and development could help them to achieve
commercial readiness more quickly.

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Decarbonisation potential of synthetic kerosene

Appendix A : Methodology for assessment of synthetic
kerosene production potential
Short term capacity development to 2030
The bottom-up ramp up model is used to estimate the synthetic kerosene capacity development to
2030 at both European and global scale. It represents the average scale up potential of the synthetic
kerosene supply and is based on information gathered on companies currently developing synthetic
kerosene technologies and the plants they operate or new plants they have announced.
The likely future deployment of each route is then assessed based on the following key factors that
influence how far and how fast a route can progress:
•
•
•
•
•
•
•
•

Project timeline: how long it takes to build each plant.
Lifetime: How many years each plant operates for.
Plant capacity: How large each plant is.
Utilisation rate: How many hours per year a plant operates for.
Initiation rate: How many commercial projects can be started each year?
Launch points: How soon after a previous project starts is it is feasible for the next project to start.
Success rate: How many of these plants and developers might fail/be unsuccessful.
Number of developers independently starting projects.

Given the large degree of uncertainty in how these factors will evolve and vary to 2030, two scenarios
reflecting slow and fast industry growth have been considered. The slow and fast growth scenarios
differ in terms of the initiation rate, the launch-point and the success rate. The two scenarios are
developed both globally and for the EU region.

Supply
scale-up

Geography
Fast growth
Europe
Slow growth
Europe

Fast growth
Global
Slow growth
Global

Figure 44: Summary of sustainable scale up scenarios.

Project timelines
The development timeline defines how long it would take to go through all the project phases until
from project inception to a fully operational plant. This includes Project development & financing (PD),
Construction (CO), Commissioning & ramp-up (CM) phases. For each technology type (biological,
thermochemical and chemical) and for each stage of plant scale-up (pilot, demonstration, 1st
commercial, 2nd commercial and Nth commercial) an average development timeline is applied, as
illustrated in Figure 45.

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Decarbonisation potential of synthetic kerosene

Figure 45: Illustrative development timeline assumptions

Small pilot and demo plants are relatively quick to design, build and commission, whereas 1st
commercial plants typically take the longest number of years to become fully operational. For
subsequent commercial plants (2nd and Nth commercial plants) the development timeline is assumed
to be quicker, due to developer learning and replication of technical plans, contracts etc.
Thermochemical routes are the most capital intensive and will typically have longer timelines.
Chemical routes are the least capital intensive with shorter timelines. Biological routes generally lie
somewhere in between.

Lifetime of plants
The following assumptions were made concerning plant lifetimes:
•
•
•

Pilot plant = 3 years
Demonstration plant = 5 years
Commercial plant = 28 years

By taking this approach, any pilot and demo plants built early in the timespan modelled do not
contribute to the total production capacities at the end of the period. The short lifetime of pilot and
demonstration plants reflects the fact that they are often loss-making facilities. Generally, developers
only operate these plants until gaining enough valuable test data and experience, to finance future
plants. Given that the nominal capacity of pilot and demo scale plants are very small compared to the
commercial facilities, the length of their lifetimes has limited impact on the overall ramp-up results.

Generic plant output
The 1st commercial and 2nd commercial plant nominal capacities were based on the size of plants
already constructed or planned by companies. For Nth commercial plants, it was assumed that each
technology route converged to using an average output fuel capacity per year figure for all the Nth
commercial plants within that route. If the nominal capacity of any plants at earlier maturity stage was
unknown, a percentage of the Nth commercial plant nominal capacity was assumed (Table 13).

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Decarbonisation potential of synthetic kerosene
Table 12: Theoretical nameplate capacities of commercial plants assumed in modelling

Conversion route

million
litres/yr

PJ/yr

CO fermentation: Fermentation of CO to ethanol
Alcohol to jet: Ethanol to jet synthesis
CO + FT: CO + Fischer-Tropsch to jet synthesis
Green FT: Renewable hydrogen + CO2 to FischerTropsch jet synthesis
Green methanol: Renewable hydrogen + CO2 to
methanol synthesis
Blue methanol: Blue hydrogen + CO2 to methanol
synthesis
Methanol-to-Jet: Green or blue methanol to jet
synthesis

139
183
519
111

2.9
6.3
17.8
3.8

195

3.1

467

7.4

163

5.8

The assumptions around the capacity of Nth commercial plants are provided in Table 13. These are not
assumed to vary by scenario, given the economically viable plant scales are not particularly dependent
on the wider industry development – rather they depend on capital costs, operating costs and
efficiencies, trading off against feedstock prices and local availability near plants (or imports). Within
the considered timespan, there will not be multiple rounds of Nth commercial plants built, so these
assumptions will apply to all modelled Nth commercial plants.
Table 13: Nameplate capacities assumptions by plant maturity, in percentage of Nth commercial plant

Nominal capacity assumption
Pilot plant
Demonstration plant
1st Commercial plant
2nd Commercial plant

%
1
10
80
80

Availability of plants
All plants across all routes were assumed to run at 90% utilisation once successfully constructed and
commissioned. This means that the actual annual fuel production is slightly below the nameplate
capacities.

Number of developers
The number of developers is a key determinant of future deployment of a specific technology. Each
developer is expected to take their technology to commercial scale (subject to any failure rates) and
start initiating new commercial projects (either under an owner operator or licensing model).
Table 14 outlines the number of technology developers globally for each conversion route as of
today. These were not assumed to vary by scenario or over time, as this number is an actual, current
number of developers within each route. This is based on the working principle to include only
developers which have at least a pilot plant. Lab-scale facilities – often in research institute – are

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Decarbonisation potential of synthetic kerosene
excluded. The ramp up model does not consider the potential entry of new developers or the
termination of activity of currently active developers.
Table 14: Number of technology developers worldwide

Conversion route
CO fermentation: Fermentation of CO to ethanol
Alcohol to jet: Ethanol to jet synthesis
CO + FT: CO + Fischer-Tropsch to jet synthesis
Green FT: Renewable hydrogen + CO2 to FischerTropsch to jet synthesis
Blue FT: Blue hydrogen + CO2 to Fischer-Tropsch
to jet synthesis
Green methanol: Renewable hydrogen + CO2 to
methanol synthesis
Blue methanol: Blue hydrogen + CO2 to methanol
synthesis
Methanol-to-Jet: Green or blue methanol to jet
synthesis

1
5
1
8
0
24
0
1

Initiation rate
The initiation rate is the number of Nth commercial projects that start construction per year (globally),
per developer. The main drivers underpinning the initiation rate are the attractiveness of licensing the
technology, which depends on economics, constraints (such as feedstocks), and the capacity of each
Nth commercial plant.
The initiation rates assumed are summarised in Table 15.
Table 15: Number of N th commercial projects started each year, by developer for the considered
conversion routes

Conversion route

Slow Growth
#/year

Fast Growth
#/year

1

2

Launch-points
The launch points define when the next maturity stage (project) is most likely to start (
Table 16). These were assumed to vary according to the technology stage, and between scenarios, but
not vary significantly between technologies, reflecting the fact that investors are likely to require a
similar number of years of operational evidence before taking larger investment decisions,
independent of the specific technology.
Table 16: Launch point assumptions for each maturity stage

Maturity stage

Rules

Pilot

Only actual or announced pilot plants will be
featured

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Slow Growth
(years)

Fast Growth
(years)

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Decarbonisation potential of synthetic kerosene
Slow Growth
(years)

Fast Growth
(years)

Demonstration

Any actual or announced demo projects will be
featured.
If no plans, demo project development assumed to
begin # (see right) years after the start of pilot
operations

1

0.5

1st commercial

Any actual or announced projects will be featured.
If no plans, 1st commercial plant construction
assumed to begin # (see right) years after the start
of demonstration operations. Investors often
require ~10,000hrs of operational data before
investing in a 1st commercial plant

3

2

2nd commercial

Any actual or announced projects will be featured.
If no plans, 2nd commercial plant construction
assumed to begin # (see right) years after the start
of 1st commercial plant operations

3

2

Nth commercial

Nth commercial construction begins # (see right)
years after the start of 2nd commercial plant
construction.
Several plants can be initiated simultaneously (see
initiation rate slide), with the same number of new
plants initiated the next year, and the next year,
etc.

2

1.5

Maturity stage

Rules

Success rate
Projects and developers may not be successful. For this reason a % success rate was used to define the
expectation of any particular project being successful from inception to operation (Figure 46 and Figure
47).

Figure 46: Success rate assumptions by technology state, in the Slow Growth

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Figure 47: Success rate assumptions by technology state, in the Fast Growth

The compounded success rates, on the right-hand side of the tables, accounts for the impact of the
success of preceding plants on the success rate of a forecasted plant. For example, if a developer is
currently operating a demonstration plant its individual success will have an impact on the likelihood
of success of a future 1st commercial plant. The compounded success rate % is a factor employed to
account for the interdependency of success rates between plants of different maturity scales of the
same developer. This factor is applied to individual plant production outputs to calculate the likely
average fuel production.

Validation of input assumptions and results
E4tech have previously validated many of the assumptions in this model with fuel producers, and in
addition we reached out to developers of Alcohol to jet and Fischer-Tropsch technology to validate
specifically the kerosene production slate assumed in this model.

Product slate
Synthetic kerosene production produces a range of hydrocarbons including jet and naphtha, as well as
other fuel types. The final distribution of hydrocarbon products is affected by many different factors
including commercial and technical factors, such as tailoring of specific conditions within the different
processing steps. As a result, for each technology an ‘aviation optimised’ scenario is given, which
favours the production of the kerosene fraction. This translates into a product slate factor which is
applied to the capacity output obtained for each route.
The percentage of jet fuel (as a percentage of total fuel output from the plant) is shown in Table 17.
Note that an average kerosene fraction of 55% was assumed for the Fischer-Tropsch route. Given
strong policy support for the SAF market, this fraction could be much higher (nearer 80%), if process
conditions, reactor design and catalyst performance are optimised. However, uncertainty around
transport policy and the relative support incentives between road and aviation markets is likely to
prevail over the next decade, so for this reason choosing a more conservative kerosene fraction
appears to be more reasonable.
Table 17: High kerosene slate

Route
Alcohol to jet: Ethanol to jet synthesis

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Decarbonisation potential of synthetic kerosene
CO + FT: CO + Fischer-Tropsch to jet synthesis: 82
Green FT: Renewable hydrogen + CO2 to Fischer-Tropsch83
Methanol-to-Jet: Green or blue methanol to jet synthesis

55%
55%
90%

The conversion routes Methanol-to-Jet (routes 4-6, 10-12) and CO fermentation to jet (route 13)
produce synthetic kerosene via the intermediates of methanol and ethanol respectively. For modelling
purposes, the production of the intermediate alcohols was modelled separately from the jet fuel
synthesis. This reflects the trends observed amongst technology developers. For example, a power-tomethanol producer may choose to sell the e-methanol into various markets such as maritime or
aviation fuels. As such, these intermediate routes are treated as low carbon feedstocks needed to
produce jet fuel via the Methanol-to-Jet and the alcohol to jet routes.
Table 18: Conversion routes of “intermediates” treated as feedstock availability for synthetic
kerosene synthesis
Route
Fermentation of CO to ethanol
Green hydrogen + CO2 to methanol
Blue hydrogen + CO2 to methanol

Long term outlook to 2050
It is likely that the landscape of the aviation industry and the policy framework around it will have
changed considerably by 2030. Current early-stage synthetic kerosene technologies could significantly
mature within the next 10 years, and new technologies may be developed. Furthermore, new
developers or companies are likely to enter the industry. Additionally, policy mechanisms should boost
the uptake of synthetic kerosene technologies to decarbonise the aviation sector. The validity of
assumptions made for the bottom-up approach to 2030 might therefore not hold over the longer time
horizon to 2050. As technologies mature, and policy support increases, higher growth rates of synthetic
kerosene supply capacity could be expected. The longer-term picture is generally more uncertain and
reflects the development of the whole aviation industry, the evolution of which is dependent on many
factors out of the scope of this study, such as competition between sectors and policy support.
An alternative “top-down” approach was therefore adopted to provide some insights on what the
picture might look like in Europe and globally in 2050. Capacity development for the period 2030 –
2050 is extrapolated based on a fixed annual growth rate for each of the fuel routes examined, with
the baseline being the capacity levels estimated in the short-term analysis.
The same growth rate was adopted for the extrapolation of synthetic kerosene production capacity
across both Europe and globally. Today, Europe dominates R&D activities in the aviation fuel industry.
However, given the global nature of the sector it is expected that future large-scale developments of
82 ICCT (2019) https://theicct.org/sites/default/files/publications/Alternative_jet_fuels_cost_EU_20190320.pdf, Note that much higher

proportions of jet are achievable vis that FT synthesis but this different slate would alter the economics of the process and the figures used
in the techno-economic analysis.
83 idem

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Decarbonisation potential of synthetic kerosene
synthetic kerosene plants are not bound to one specific geography. In summary, a constant growth
rate is applied for the scale up of each synthetic kerosene route from 2030 onwards.
The growth rate applied differs between the different type of routes, i.e. steel mill waste gas based
routes, power-to-liquids based routes and blue hydrogen based routes. The selected growth rates are
and reasoning for their selection is summarised in Table 19.
Table 19: Summary of selected growth rates for synthetic kerosene scale up post 2030
Route
Steel mill waste
to ethanol to jet

CAGR
15%

Growth rate basis
Global HVO production
between 2019 and 202584

Reasoning
Assuming the steel mill waste fermentation route reaches
TRL 9 in 2030, the growth will be affected by market
demand and feedstock availability.
This routes shares similarities with the HVO conversion
route as in both cases the build-up of sales into the fuels
market is affected by long term feedstock constraints.

Power-to-Liquids
routes

21%

Average of global PV
industry growth85 (21%)
between 2015 and 2019.
and global offshore wind
industry86 (20%) in 2018

Blue routes

10%

Based on global CO2
capture and storage
capacity88

The large-scale supply of renewable power is seen as the
limiting factor on the power-to-liquids scale-up, especially
given the growing competition for renewable power
between different end sectors (heating, buildings,
transport). The proxy is based on the average growth rates
of the PV and offshore wind industries. While the offshore
market grew by 30% between 2010 and 201887, the latest
growth rate in 2019 is assumed to be more representative of
the long term.
The supply of natural gas is likely to be sufficient, however,
carbon capture and storage capacity is expected to be the
limiting factor in the scale up of the blue kerosene routes. A
recent study by Zahasky and Krevor develops scenarios for
global geologic carbon storage requirements with growth
rates ranging 8.6% to 12.1%. The CAGR of the global CO2
storage capacity is therefore a good indication of how blue
hydrogen could become available for kerosene supply.

While the deployment rates for analogous industries is considered to be a reasonable proxy for growth
in synthetic kerosene, it is important to bear in mind that other geographical, temporal and economic
aspects will be important. For this reason, applying “proxy growth” factors from analogous industries
to estimate the ramp up of synthetic kerosene from 2030 onwards, means assuming a similar context,
i.e. a highly-favourable economic and regulatory context which may not exist in support of aviation
fuel in 2030.

Location of synthetic kerosene plants
The ramp up model estimates the capacity scale up of synthetic kerosene, based on announced and
already operational plants. The location of these plants in the model matches the location
announced by the technology developer. The assumptions described above are applied to estimate
“speculative new plants” for each technology developer. Once a technology developer operates
plants at commercial scale, the model assumes new hypothetical plant locations which alternate
between Europe and Rest of the world. As described above, beyond 2030, a constant growth rate is
84 IEA, Available at: https://www.iea.org/reports/renewables-2020/transport-biofuels
85 IEA, Available at: https://www.iea.org/reports/solar-pv
86 IEA, Available at: https://www.iea.org/reports/offshore-wind
87 IEA, Available at: https://www.iea.org/reports/offshore-wind-outlook-2019
88 Zahasky C, Krevor S. Global geologic carbon storage requirements of climate change mitigation scenarios. Energy & Environmental

Science. 2020;13(6):1561-1567.

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Decarbonisation potential of synthetic kerosene
applied to the 2030 baseline. Since the majority of announced and operational synthetic kerosene
plants will be located in Europe in the short term (2030), the long-term outlook will maintain a
similar split.

Ramp up results
Note that in the following charts, the “CO to Jet” results include the CO fermentation to jet and the
CO + Fischer-Tropsch synthesis routes.
Green MtJ (routes 4-6)

Green FT (routes 1-3)

CO to Jet (routes 13-15)

TOTAL

25

Jet fuel [ Mtonnes / year ]

20

15

10

5

Figure 48: Route breakdown of synthetic kerosene in Europe to 2050 under the slow growth scenario
30

Green MtJ (routes (4-6)

Green FT (routes 1-3)

CO to Jet (routes 13-15)

TOTAL

Jet fuel [ Mtonnes / year ]

25

20

15

10

5

Figure 49: Route breakdown of synthetic kerosene in Europe to 2050 under the fast growth scenario

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Green MtJ (routes 4-6)

Green FT (routes 1-3)

CO to Jet (routes (13-15)

TOTAL

25

Jet fuel [ Mtonnes / year ]

20

15

10

5

Figure 50: Route breakdown of global synthetic kerosene to 2050 under the slow growth scenario

40

Green MtJ (routes 4-6)

Green FT (routes 1-3)

CO to Jet (routes 13-15)

TOTAL

Jet fuel [ Mtonnes / year ]

35
30
25
20
15
10

5

Figure 51: Route breakdown of global synthetic kerosene to 2050 under the fast growth scenario

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Appendix B : Techno-economic modelling
Model description
The modules constituting the routes are sized according to the final product throughput which is
estimated based on examples of existing or planned projects.
SMR + CCS

Natural Gas

Cost per kWh

Efficiency

Emissions per kWh

Capex

WGS
Synthesis
Efficiency
Capex

Opex

Opex

Water electrolysis
Efficiency

(RWGS) + FT
Synthesis

Hydrogen
Energy per tonne

Capex

Cost per tonne

Opex

Heat

PtM
Synthesis

Point
source

Renewable
Power
Cost per kWh
Emissions per kWh

Efficiency

Energy per tonne

Capex

Cost per tonne

Opex

Emissions per tonne

Efficiency

Cost per kWh

Point source
CO2 / CO

Emissions per kWh

Jet (+Gasoline /
Diesel)

Capex
Opex

DAC
Cost per tonne

Methanol

Emissions per tonne

Efficiency
Capex
Opex

MtJ
Synthesis

Jet (+Gasoline /
Diesel)

Energy per tonne

Energy per tonne

Cost per tonne

Cost per tonne
Emissions per tonne

Water

CO
Fermentation
Cost per litre

Efficiency
Capex

Ethanol

EtJ
Synthesis

Jet (+Gasoline /
Diesel)

Energy per tonne

Energy per tonne

Cost per tonne

Cost per tonne

Opex

Emissions per tonne

Figure 52 Techno-economic model structure

Data for each module (except for the CO from steel mill routes) is based on published literature and,
wherever necessary, absolute quantities (e.g. energy requirement in kWh) were normalised on
product output in order to derive relative quantities (e.g. specific energy requirement in kWh/kg).
Data for the steel mill routes are from the developers themselves and have not been peer
reviewed/validated.
The levelised cost of production of the products has been calculated including the following costs:
capital expenses for main equipment components (e.g. reactors), maintenance, stack replacements,
power utilities, heat utilities, CO2 and indirect plant costs. Capital expenses (except for stack
replacement costs) and indirect plant costs are assumed to be incurred before the commissioning of
the plant. All other expenses occur with annual frequency (except for stack replacement which is
concentrated in specific years) and are subjected to discounting. An additional module accounting for
the downstream impacts of the fuel e.g. cost and GHG emissions associated with transporting the
fuel from the production site to the airport has been included for each chain.
The energy efficiency of the route is calculated as the ratio between the energy content of the
product and the external energy input to the process. Among the external inputs there are the power
supply to the electrolyser, power supply to auxiliaries of the various modules such as pumps and fans
and thermal energy required by the process that cannot be recovered internally.

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Decarbonisation potential of synthetic kerosene
𝑃𝑎𝑡ℎ𝑤𝑎𝑦 𝐸𝑛𝑒𝑟𝑔𝑦 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 =

𝐸𝑛𝑒𝑟𝑔𝑦 𝑐𝑜𝑛𝑡𝑒𝑛𝑡 𝑜𝑓 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 (𝐿𝐻𝑉)
𝑀𝐽𝐿𝐻𝑉
[%
]
𝑃𝑜𝑤𝑒𝑟 𝑠𝑢𝑝𝑝𝑙𝑦 + 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 ℎ𝑒𝑎𝑡 𝑠𝑢𝑝𝑝𝑙𝑦
𝑀𝐽𝑖𝑛𝑝𝑢𝑡

The GHG emissions associated with each process, are evaluated considering only the main
contributors and neglecting, for example, indirect emissions of raw materials, water, construction,
etc. The exception is the CaCO3 absorbent used in DAC processes for which CO2 emissions have been
included. The main contributors to GHG emissions are: electric power supply, external thermal
power supply (which can be in different forms depending on the scenario selected) and emissions
associated with the CO2 capture process. All emissions (upstream + combustion factors) relating to
natural gas used in DAC or marginal natural gas used for point source CO2 capture is counted due to
release back to atmosphere when burnt as jet. The fossil CO2 used in fuel synthesis is considered to
have zero emissions, i.e. assuming that it is waste CO2 that would have been emitted into the
atmosphere anyway, if a power-to-liquid plant was not using it.
Integration of different parts of a process is often key to achieving high levels of material and energy
efficiency. It would be possible e.g. to feed heat back to the CO2 capture if the DAC and FT plant
were located co-located geographically and this could increase efficiency. In this model, all the
components (electrolyser, SMR, DAC, point source, FT plant, methanol route) are considered
independently, so no heat integration is included.
The model has been built with the option of exploring different scenarios with regard to the type of
electricity supply, external heat supply and CO2 origin, with implications on the levelised cost of
production and GHG emissions. The reference values were chosen to best reflect those available now
and in the future in the Netherlands, but the model offers a selection of cases to be chosen to
explore their impact on results.
Table 20 Table of assumptions

Power
Dutch grid electricity cost
Dutch grid electricity GHG
Renewable electricity cost89
Renewable electricity emissions
Heat
Dutch NG cost
Dutch NG combustion emissions
Dutch NG upstream emissions90
Green H2 GHG
Synfuel plant capacity
CO2 routes
CO fermentation + ETJ route
CO + FT routes

2020
41
0.4
73
0

2030
51
0.1
45
0

2050
51
0.0
26
0

Units
€/MWh
kgCO2e/kWh
€/MWh
kgCO2e/kWh

16.5
0.202
0.032
0

23.7
0.202
0.032
0

23.7
0.202
0.032
0

€/MWh
kgCO2e/kWh
kgCO2e/kWh
kgCO2e/kWh

5,000
30,000
n/a

30,000
92,250
505,000

100,000
315,000
505,000

tonnes/yr
tonnes/yr
tonnes/yr

89 https://www.theccc.org.uk/publication/sixth-carbon-budget/ CCC Sixth Carbon Budget Supporting information, charts and data in the

report
90
https://ec.europa.eu/jrc/en/publication/eur-scientific-and-technical-research-reports/jec-well-tank-report-v5
GMCG1 pathway, up to point of compression and dispensing

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Decarbonisation potential of synthetic kerosene
(both WGS and blue H2)
The renewable energy costs used are generation cost projections for wind/solar and do not include
grid balancing/peaking plant and storage costs. The data is sourced from the CCC UK data 6th carbon
budget91 and converted using the current exchange rate.

FT synthesis step
The FT synthesis step combines the hydrogen produced and CO2 captured in the RWGS to produce a
dry syngas which is then fed into the FT reactor. The data for FT synthesis, including data for the
RWGS required in the standard electrolysis routes, are from Marchese et al.92, using their Case A,
90% recirculation, low pressure scenario. The FT synthesis process is exothermic and so could benefit
from heat integration in the future.
•
•
•

FT reactor has excess heat available at a constant 228oC
Exhaust gas has excess heat available from 1000oC to 50oC
Syngas cooling has excess heat available from 800oC to 25oC

Heat is required for the RWGS, and only a portion of this heat requirement could be met from excess
heat from the FT synthesis. This is because the amount of recycled heat from FT synthesis to RWGS is
limited by the amount of high temperature heat available. Therefore, the RWGS would still require
an external heat input, although this could potentially be met by electrical heating in the future. The
hydrocracker modelled was taken from Hannula et al.93 Plant scaling costs were taken from Brynolf
et al.94. The modelled chain includes RWGS combined with an FT reactor for this route but an
alternative scenario could see syngas produced by co-electrolysis of H2O and CO2 instead of via the
RWGS reaction.

Heat
Thermal energy can be provided in different ways (e.g. electricity, natural gas, hydrogen, waste heat
from other industries) with implications for both associated cost and GHG emissions. In the cases
where renewable hydrogen has been used as a heat source, it has been assumed that this has been
bought in and so the LHV of hydrogen has been used in efficiency calculations rather than the
renewable electricity from which the synthesis of this hydrogen originated.
If heat is provided by natural gas, both scope 1 (carbon content of the natural gas) and scope 2
emissions have been accounted for. While the gas grid is likely to slowly decarbonise over time with
increasing substitution of renewable methane and hydrogen, the natural gas modelled in this study is
not assumed to decarbonise with time, as projections to 2050 were not available, and new demands
from synthetic kerosene are assumed to be met by fossil natural gas given the constrained
availability of higher cost low-carbon gas sources.

91 https://www.theccc.org.uk/publication/sixth-carbon-budget/ CCC Sixth Carbon Budget Supporting information, charts and data in the

report
92 Marchese et al. (2020) Energy performance of Power-to-Liquid applications integrating biogas upgrading, reverse water gas shift, solid
oxide electrolysis and Fischer-Tropsch technologies. Available at:
https://www.sciencedirect.com/science/article/pii/S2590174520300131?via%3Dihub
93 2013, "Liquid transportation fuels via large-scale fluidised-bed gasification of lignocellulosic biomass".
94 Brynolf et al., 2018, "Electrofuels for the transport sector: A review of production costs"

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Decarbonisation potential of synthetic kerosene
If heat is provided by renewable hydrogen or renewable electricity, it has zero associated CO2
emissions.

General modelling assumptions
Other important parameters affecting the results of the analysis are:
•

•
•

•

•

•

•

•

•
•

Capex annualization discount rate. This is the rate at which future expense are discounted to
present value and is equal to the WACC of the project. In this study a typical value of 7% has been
chosen, chosen based on E4tech analysis.
Plant lifetime. Assumed to be 25 years unless stated otherwise.
Yearly plant utilisation. Plants require yearly maintenance during which the plant needs to be shut
down. For this reason, a yearly utilisation factor of 85% (~7450hrs) has been used, which is applied
to the nameplate throughput of the plant to obtain the actual annual production.
Indirect plant costs. These represent investment costs associated to the realisation of the whole
plant including for example engineering and construction, fees and project contingency cost.
Indirect plant costs are estimated in an aggregate way as a proportion of the plant equipment cost.
Based on Brynolf et al. (2018)95 these costs are estimated to be 100% of plant equipment cost.
For the steel mill CO with WGS route, there is no heat integration in the 2030 plant so a heat
source must be used to generate the steam, but integration with waste heat or electrification are
possible ways the plant could be improved in the future. However, the FT reactor does produce a
lot of water, which has been recycled within the system boundary as the water source for the
steam generation.
Water - this depends on location but in most cases costs are likely to be negligible compared to
other costs given the low water consumption of electrolysis96 and low prices of water (~ €1/m3
for industrial users). For this reason, water costs (and GHG emissions) have not been included in
this study.
Transport from the production plant to the airport refuelling site uses a value of 0.65 gCO2e/MJ
of jet taken from the CCC 6th Carbon budget and the "transport to airport" cost estimate is from
an LBST study97
CCS costs - The cost of carbon capture is included in the costs of the generation technologies
themselves; dehydration and compression of the captured CO2 are included within the SMR
plant boundary. However, downstream transport and storage costs for this CO2 have been
added separately for both blue H2 production and the CO + WGS route. A value of €17/tCO2 was
used, taken from the CCC 6th Carbon budget for North Sea storage.
GHG abatement - a fossil jet price of $600 has been used with emissions of 4136 kgCO2 per
tonne jet fuel.
Data for the steel mill routes are from the developers themselves and have not been built up in
the same manner as for the other routes but where possible common input data has been used.
The assumptions have been validated as far as possible against other peer reviewed data
sources.

95 Brynolf et al., 2018, "Electrofuels for the transport sector: A review of production costs"
96 Water consumption for PEM electrolysers is 0.51 litres potable water per kWh H2 HHV

(https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/760479/H2_supply_chain_evidence_
-_publication_version.pdf)
97 LBST, 2016, Power-to-Liquids Potentials and Perspectives for the Future Supply of Renewable Aviation Fuel
http://www.lbst.de/news/2016_docs/161005_uba_hintergrund_ptl_barrierrefrei.pdf

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Decarbonisation potential of synthetic kerosene

Methanol routes

% efficiency - MTJ routes

100%

% efficiency

90%
80%
70%
60%
50%

2020

40%

2030

30%

2050

20%
10%
0%
H2 source:
CO2 source:

Green
Bio PS
Route 4

Green
Fossil PS
Route 5

Green
DAC2
Route 6

Blue
Bio PS
Route 10

Blue
Fossil PS
Route 11

Blue
DAC1
Route 12

Figure 53: LHV energy efficiency for methanol routes

Within each route, the
columns are for 2020, 2030
and 2050 data moving left
to right

Figure 54: Production costs for methanol routes

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Decarbonisation potential of synthetic kerosene

Figure 55: GHG emissions for methanol routes

The input parameters used in the model are subject to considerable uncertainty and consequently a
sensitivity analysis has been carried out to highlight the effect on fuel prices of varying certain input
parameters.

Sensitivity analysis

Within each route, the
columns are for 2020, 2030
and 2050 data moving left
to right

Figure 56: Source of energy input

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Decarbonisation potential of synthetic kerosene
Figure 56 shows the energy requirement for each route differentiated by energy source. It can
therefore be implied how changes in either the costs or the GHG emissions of these constituent
components will impact the overall chain as a whole. More detailed sensitivity analyses on specific
parameters were carried out and displayed below for the FT routes.
Production costs sensitivities - Impact of renewable energy cost - FT routes
8000
Within each route, the
columns are for 2020,
2030 and 2050 data
moving left to right

Production cost (€/tonne efuel)

7000
6000

5000
4000

Central case
10% lower

3000

10% higher

2000
1000

0
1

2

3

4

5

6

7

8

9

10

11

Route number
Figure 57: Sensitivity of synthetic kerosene cost to renewable electricity price (green H2 routes)

Within each route,
the columns are for
2020, 2030 and
2050 data moving
left to right

Figure 58: Sensitivity of synthetic kerosene cost to natural gas price (blue H2 routes)

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Decarbonisation potential of synthetic kerosene

Within each route,
the columns are for
2020, 2030 and
2050 data moving
left to right

Figure 59: Sensitivity of synthetic kerosene cost to electrolyser efficiency (green H2 routes)

Within each route,
the columns are for
2020, 2030 and
2050 data moving
left to right

Figure 60: Sensitivity of synthetic kerosene cost to electrolyser CAPEX (green H2 routes)

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Decarbonisation potential of synthetic kerosene

Within each route,
the columns are for
2020, 2030 and
2050 data moving
left to right

Figure 61: Sensitivity of synthetic kerosene cost to substituting SMR with ATR (blue H2 routes)

SMR has no electricity input whereas ATR does, so the lifecycle GHG emissions improve as the grid
decarbonises.

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Decarbonisation potential of synthetic kerosene

Appendix C : Descriptions of Water Gas Shift (WGS) and
Reverse Water Gas Shift (RWGS)
Water Gas Shift Reaction
In the WGSR, water reacts with CO to form hydrogen
and carbon dioxide (CO + H2O ↔ CO2 + H2), where
the CO2 can be separated from the stream to get
pure hydrogen98

The WGS reaction mechanism is considered to be
complicated due to the sensitivity of the catalysts to
minor changes in operational conditions. There are
two prominent mechanisms for the WGS reaction:
the regenerative (redox) mechanism and the
associative (Langmuir-Hinshelwood) mechanism.
Generally, at high temperatures, the WGS reaction is
accepted to follow the redox mechanism, where CO
molecule adorbs on the catalyst surface and
abstracts one oxygen from the metal-oxide support
to form carbon dioxide. Loss of oxygen from metaloxide creates an oxygen vacancy that is fulfilled by
dissociating a water molecule to generate hydrogen
and oxygen atoms. Hydrogen atoms combine and
desorb as hydrogen gas whereas oxygen atom is
captured by the oxygen deficient metal-oxide. The
associative mechanism, on the other hand, has been
reported at low as well as high temperatures, usually
proceeds by the adsorption of CO and H2O on the
catalysts surface leading to a reactive intermediate
that subsequently decomposes to produce CO2 and
H2. Nonetheless, the redox mechanism is still the
most widely accepted mechanism for WGSR101.
WGSR is a well-established procedure in
conventional chemical/hydrocarbon industries for
the production of ammonia, methanol, hydrogen,
saturated hydrocarbons, and many other chemicals
and petrochemicals103.

Reverse Water Gas Shift Reaction
The RWGS reaction is the reversible hydrogenation
of CO2 to produce CO and H2O99. The RWGS is
equilibrium limited, and favoured at high
temperatures (600-900°C) due to the endothermic
nature of the reaction100. The heat input
requirement makes RWGS a more complex
technical system compared to WGS.
Numerous studies have been carried out regarding
catalysis of the RWGS reaction. Iron based catalysts
are often considered as one of the most successful
active metals for higher temperatures, due to its
thermal stability and high oxygen mobility. Typically
iron works in the high temperature range and for
lower temperatures copper is often regarded to be
successful due to its enhanced adsorption of
reaction intermediates at these lower
temperatures102.

Only a few plants have been installed until now (e.g.
at the Sunfire PtL pilot plant in Dresden, at KIT in
Karlsruhe, and at the SOLETAIR PtL pilot plant in
Lappeenranta in Finland)

98 Available at: https://link.springer.com/content/pdf/10.1007/s42247-020-00116-y.pdf
99 Available at: https://www.sciencedirect.com/science/article/pii/S221298201730433X
100 Available at: https://par.nsf.gov/servlets/purl/10104077
101 Available at: https://link.springer.com/content/pdf/10.1007/s42247-020-00116-y.pdf
102 Available at: https://www.sciencedirect.com/science/article/pii/S221298201730433X
103 Available at: https://link.springer.com/content/pdf/10.1007/s42247-020-00116-y.pdf

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