AMF Annex 58 /IEA Bioenergy Task 41 Project 10
A Report from the Advanced Motor
Fuels TCP and IEA Bioenergy TCP

The Role of Renewable
Transport Fuels in
Decarbonizing Road Transport
Production Technologies and Costs
Adam Brown
Energy Insights Ltd

Lars Waldheim
Waldheim Consulting

Mahmood EbadianJack Saddler
University of British Columbia

Edited by Dina Bacovsky
BEST — Bioenergy andSustainable Technologies GmbH

Nils-Olof Nylund
Päivi Aakko-Saksa
VTT Technical ResearchCentre of Finland Ltd
November 2020

Summary / Abstract
This report constitutes Part 2 of the report on “The Role of Renewable Transport Fuels in
Decarbonizing Road Transport”. In this report the term decarbonization includes all
options to reduce GHG emissions and make road transport cleaner, including low(-fossil)carbon energy carriers such as biofuels, e-fuels, and renewable electricity. This part of thereport deals with all aspects of the production and use of renewable transport fuels.
Since the early 2000s, renewable transport fuels have been introduced in many countries
around the globe. Biomass is a renewable source of carbon and its use for bioenergy andbiofuels contributes to a circular economy. Biofuel production not only produces biofuels but
also valuable by-products, and provides value to the local biomass producers.
While our assessment of the development of the transport sector in selected countries
shows clearly that the required full decarbonization can only be reached with a combinationof biofuels, electric vehicles and eventually also e-fuels, the question arises whether there
will be sufficient renewable transport fuels available to support national and global needs. A
large number of different renewable transport fuels exists, produced from a variety offeedstocks through a range of different production technologies. Some of these fuels arecompatible with existing engines, others have to be used in low blends with fossil fuels or in
dedicated engines. The multitude of options makes it difficult for policy makers to decide
which fuel options to go for to decarbonize their transport sectors.

Low-carbon fuel technologies and their development status
Low-carbon transport fuels can be produced from:•biogenic feedstocks or biogenic fraction of wastes (“biofuels”)•

energy and carbon contained in fossil wastes and residue streams or the fossil
fraction of such materials (“e.g. recycled carbon fuels”)•

energy from other renewable sources, sometimes in combination with carbon atoms
from biogenic and fossil sources (CCU) (“renewable fuels”)

The technology readiness levels (TRL) of the production technologies for these fuels vary,as depicted in the figure on the following page.
Technologies for the production of established biofuels such as ethanol from sugar andstarch crops, biodiesel from triglycerides and lipids, hydrogenated triglycerides and lipids,
and biomethane from upgrading of anaerobic digestion biogas are at TRL9.

iTechnology Readiness Level (TRL)

Emerging Biofuels

Established biofuels

Raw material

Technology

Fuel

Fermentation

Ethanol

Transesterification

FAME/Biodiesel

Hydrotreatment

Drop-in hydrocarbons

Crops, sludges, manures etc.

AD biogas
upgrading

Biomethane

Raw material

Technology

Fuel

Enzymatichydrolysis +fermentation

EthanolLignocellulosic feedstocks

Sugar

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

StarchVegetable oils & lipid waste

Lignocellulosics , biogenic
fraction of RDF etc., nonlignocellulosic biomass or
by-products
Lignocellulosics , biogenic
fraction of RDF etc., nonlignocellulosic biomass or
by-products
Lignin from lignocellulosic
ethanol or forestry liquors

Other alcohols

Gasification +fermentation

Ethanol

Gasification +catalytic synthesis

Drop-in hydrocarbons,
Alcohols, Biomethane

Pyrolysis +upgradingDrop-in hydrocarbons

HTL + upgrading

Drop-in hydrocarbons

HTL and/or
chem. treatment+ upgrading

Drop-in hydrocarbons

Drop-in hydrocarbons

E-fuels

Recycle Carbon Fuels

Sugars from sugar andstarch crops or
lignocellulosic

Fermentation
Various alcohols
C hem. conversion

Drop-in hydrocarbons

Non-LC biomass fractions or
by-products

Various

Various

Supply of fossil waste or byproduct gases

Technology

Fuel

Fermentation
Steel industry & chemicalindustry off-gases

Ethanol
MethanolC atalytic
synthesis

Gasification +Wastes, waste plastics, noncatalytic synthesis
bio fraction of RDF
or fermentation

MethaneDrop-in hydrocarbons,
Alcohols, Biomethane

Waste plastic fraction

Pyrolysis +distillation

Drop-in hydrocarbons

Supply of H2

Technology

FuelElectrolysis

Hydrogen
MethanolRE electricity

Electrolysis andcarbon capture+
catalytic synthesis

MethaneDrop-in hydrocarbons

Overview of technology pathways and their technology readiness level (TRL)

Emerging biofuel pathways include ethanol from lignocellulosic feedstocks, gasificationderived biofuels, pyrolysis-derived intermediates, hydrothermal liquefaction-derived
intermediates, lignin-derived intermediates, sugars to biofuels, and biofuels derived fromii

non-lignocellulosic biomass such as microalgae. TRLs for these technologies range from 3
to 8.
Recycled carbon fuels include ethanol, methanol and methane produced from industry offgases, and fuels derived from the gasification or pyrolysis of non-biogenic wastes or
fractions of wastes, with TRLs ranging from 4 to 9.
E-fuels include hydrogen, methanol, methane and Fischer-Tropsch liquids. While theproduction of hydrogen through electrolysis is at TRL9, the other pathways are at TRL 4-6.
Terminology for different low-carbon fuels is not consistent globally. In the EU fuels areclassified by feedstock, in the USA by pathway, and in Brazil by the carbon intensity of thefuel. In particular, the term advanced biofuel has different meanings in different jurisdictions.
Terminology used in this report
In this report a distinction is being made between established biofuel pathways andemerging biofuel pathways. This is to avoid terms like first and second generation, 1G,
2G, conventional and advanced, as these terms have no homogeneous definition and areused differently in different regions and jurisdictions. Further fuel types mentioned in thereport include recycled carbon fuels and e-fuels. Further descriptions of these categories areprovided in Figure 1 and the explanatory text below.
The same figure also provides the linkage between fuel production pathway, i.e. feedstockand conversion technology used, and the chemical nature of the resulting fuel. When appliedin engines it is the chemical composition of the fuel that matters, not the feedstock. Thus,
some fuels are grouped, e.g. FT-liquids and HVO1 into drop-in hydrocarbons2.
The linkage between these fuels and the marketed fuel qualities is provided inTable 6, which also describes the applicability of these fuel qualities in different engines.

1

HEFA (Hydroprocessed Esters and Fatty Acids), also called HVO (Hydrotreated Vegetable Oil), is a renewablediesel fuel that can be produced from a wide array of vegetable oils and fats. The term HEFA or HVO is usedcollectively for these biogenic hydrocarbon-based renewable biofuels. HVO is free of aromatics and sulfur andhas a high cetane number.
2“Drop-in” biofuels are defined as liquid hydrocarbons that are oxygen-free and functionally equivalent topetroleum transportation fuel blendstocks.

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Availability and costs of sustainable bioenergy feedstocks forbiofuels production
The theoretical availability and cost modelling indicate that large volumes of sustainable
feedstock could be made available for biofuels production, sufficient to meet likely future
demand as indicated in low carbon scenarios. Most of the material necessary could be
supplied from wastes and residues, and from sustainable forestry practices. Agriculture canalso be an important source of raw materials, with feedstocks produced in ways which
complement traditional agricultural production through co-cropping and through use of lessproductive land.
Estimates of the potential available biomass and other uses vary significantly in theliterature. While the theoretical potential is high, the economic availability can vary greatly,
depending on numerous factors including yield and regional parameters (e.g. location andsize of crop/forest lands, local infrastructure, etc.). There is a wide range of biomass
availability globally, from as low as 95 Exajoule (EJ)/year to as high as 350 EJ/year.
National studies indicate that much of the raw material could be produced and delivered tousers at costs of between 3 - 6 EUR/GJ. More information from real projects is needed totest the costs of procuring suitable feedstock in the real world.
The overall biomass cost is highly case dependent and successful management of biomass
supply chains will be critical if future investments in biofuels are to be realized. Despite
efforts to reduce the cost of biomass and associated logistics, it is anticipated that increasing
competition for commercial quantities of biomass will result in an increase in the price of thebiomass feedstock.
National and regional assessments are very helpful in providing insights into likely long-term
availability and costs of feedstocks for bioenergy production, including for the production ofadvanced biofuels. However, in order to be useful for estimating long term global availability
such assessments need to be done in a very transparent way, with clear classification of thevarious resources and of the assumptions made in defining how much material could inpractice be available, and around the sustainability considerations applied.
A useful step in harmonizing such approaches would be the development of some bestpractice guidelines for such studies, including some standardization and rationalization of theclassification of the various potential feedstocks, and of the sustainability constraints which
are applied. Such measures could facilitate the development of more consistent resource
estimates, which could be more easily compiled to give a global estimate, at least for key
producer and user regions.
iv

As shown in the figure on the next page, IRENA estimates the global biomass energy supply
potential in 2030 to be in the range of 97 to 147 EJ/year. Feedstocks considered include
energy crops, agricultural residues, processing residues, animal and food wastes, fuel wood,forest biomass and wood waste. Largest supply potentials stem from Asia, Europe and North
America. Growth in biomass supply potential will be (among other factors) supported byincreased plantation areas both for food/feed crops as well as for forests, higher yields ofenergy crops, and higher recovery of agricultural and processing residues.

Potential global biomass supply in 2030 (Adapted from IRENA, 2014)

Domestic biomass resources can be classified into three supply cost groups:•< USD 5 per GJ: processing residues and wastes•

USD 5-8 per GJ: harvesting residues•> USD 8 per GJ: bioenergy crops and fuel wood

As depicted in the figure on the next page, the average, global cost of biomass is about USD
8.3 per GJ, with the cost of domestic biomass ranging from as low as USD 3 per GJ in Africa(agricultural processing residues) to as high at USD 17 per GJ for bioenergy crops in moredeveloped parts of the world. The amount of exportable biomass available in regions withsurplus biomass is estimated to be about 26% of the total global supply potential. However,the costs associated with transporting this biomass to different world regions are estimatedto add an average of USD 3 per GJ to domestic prices.
v

The overall biomass cost is highly case dependent and successful management of biomass
supply chains will be critical if future investments in bioenergy and biofuels are to berealized. Despite efforts to reduce the cost of biomass and associated logistics, it isanticipated that increasing competition for commercial quantities of biomass will result in an
increase in the price of the biomass feedstock.

Projected annual global supply for primary biomass in 2030

GHG emissions of emerging biofuel pathways
Current legislation in the USA and the European Union require advanced biofuels to show atleast 50% / 65% reduction in GHG emissions respectively, as compared to their fossil fuelequivalents. The carbon intensity of a fuel is measured in gCO2e/MJ using Life Cycle
Assessment (LCA) and represents the GHG emissions emitted across the full life cycle of a
product system, from feedstock acquisition to production, use, and final disposition. Carbon
intensity of gasoline and diesel is about 95 gCO2e/MJ.
Emerging biofuels, termed advanced by either USA or EU legislation, do not automaticallyhave lower carbon intensity values than those of established biofuels. However, among thevarious pathways that have been certified under California Low Carbon Fuel Standard(LCFS) program, the average carbon intensity values of advanced biofuels are typically,sometimes significantly, lower than those of established biofuels, see figure below for
details. The current average CI values of biofuels (both established and emerging pathways)
provided to California range from 15 to 65 gCO2e/MJ, and can also be negative whenobtaining credits for avoided GHG emissions from waste disposal or if combined with CCS.
vi

Minimum, average, and maximum carbon intensity (CI) values of some of the fuel pathways certified under
California LCFS program in 2019

The location/region where the biofuel production facility is located will be a key component of
the final carbon intensity of the fuel. This is due to factors such as access to low carbon
intensity energy sources for heat and power, the potential to co-locate with other biofuel
plants or oil refineries to develop efficient biofuel production and supply chains, the type of
biofuels and co-products produced, the type of feedstock and associated logistics, land typeused for crop/biomass cultivation and agronomic practices, the local regulations on the useof feedstock, and carbon accounting mechanisms for biomass.
As LCFS-type policies become more common in increasing numbers of jurisdictions, thecarbon intensity of current and emerging biofuels is expected to decrease.

Role of policy on production and use of emerging biofuels
Policies have been and will continue to be essential to foster the growth of the advanced
biofuels used to decarbonize transport, particularly long-distance transport. Policies used
include blending mandates, excise tax reductions or exemptions, renewable or low carbon
fuel standards, as well as a variety of fiscal incentives and public financing mechanisms.
Countries that use a mixture of market-pull and technology-push policy instruments havebeen most successful at increasing biofuels production and use and also at developing anddeploying less mature emerging biofuels production technologies.

vii

Technology-push and market-pull biofuel policies.

So far, most of the policies used to promote transport decarbonization have focused on roadtransport. Other transport sectors, such as rail, aviation and shipping, have, until recently,
received comparably less policy attention despite being large energy consumers and GHG
emitters. However, transport policies and industry efforts are increasingly focused on
decarbonizing long-haul transport sectors (i.e., road, rail, aviation and shipping), where
electrification is much more challenging.
While the production and use of transport biofuels has more than doubled over the last
decade, progress in expanding biofuels production remains well below the levels required todecarbonize transport significantly. Several factors continue to impact the effectiveness of
biofuels policies such as relatively low petroleum and fossil fuel prices, uncertainty about
future policy and funding programs to support conventional and advanced biofuels, theinconsistent regulation of global trade of biofuels and continuing concerns related to foodsecurity, land use change and overall sustainability.

The likely costs of emerging biofuels production and the scope forcost reduction
The costs of producing emerging biofuels have been assessed in a recent IEA Bioenergy
study. The costs are currently significantly higher than the current costs of fossil fuelequivalents, see figure below.

viii

50 Production cost EUR/GJ

40

30

20
Feedstock Costs
Operating Costs

10

Capital

Total
0

- 10

Low High Low High Low High Low High Low High Low High Low High Low High Low High Low High
Cellulosic
Cellulosic Methanol and Methanol and FT Liquids – FT Liquids –Bio-oil Bio-oil Biomass
Wastes coprocessing standalone
methaneethanol ethanol “1 1/2 methaneGen”
biomass
wastesHVO

AD

Summary of current cost ranges. Note: “Cellulosic ethanol”, 1.5 Generation most frequently refers to the
production of cellulosic (such as corn fiber) ethanol integrated into a corn-based ethanol plant.

There is significant potential for reducing the costs of the assessed range of emerging
biofuels. In order to achieve these, projects must first demonstrate in practice that thecurrent production objectives in terms of reliable production at high availability and efficiency
can be achieved consistently. The reductions will only then be achieved if there areopportunities to build a significant number of further generations of plants which will allow
experience to accumulate and provide the basis for learning, and for growing confidence inthe technologies. The figure on the next page shows possible future emerging biofuel
production cost ranges, after improvements in the process and after gaining access tocapital at lower cost.

ixPotential costs of biofuels production after reductions

Large scale deployment will depend on continuing policy support. First, industry will needsupport during the demonstration and risky and costly early commercialization of thetechnologies, so as to bridge the “valley of death”. And then, continuing strong support will
be needed to offset the differences between biofuels and fossil fuel prices, and to incentivize
low carbon transport fuels.
While the costs of the emerging biofuels and other fuels discussed above are an importantfactor, a broader range of issues also need to be considered when comparing these options
and also when looking at other low-carbon options. These include the extent to which they
can directly replace fossil fuels, the costs of any modifications or of distribution costs
associated with fuels, the likely availability of feedstocks and the life-cycle GHG emissions
associated with particular routes. The overall consideration of the future for emerging
biofuels need to be seen in the context of these other factors, and based on an analysis offull system costs, feedstock availability and life-cycle GHG emissions.

Compatibility of fuels with existing engines
The compatibility of fuels with fuel infrastructure and vehicles includes the aspects material
compatibility, tolerance, vehicle compatibility and vehicle compliance, i.e. fulfilment of all
regulatory requirements concerning pollutant emissions and safe vehicle use. Biofuels canbe used in low blends, as drop-in fuels with up to 100% substitution, or as special fuels in
dedicated or adapted engines. The table on the next page provides an overview on fuels andtheir applicability in engines.
xApplication of transport fuels

Fuel

Application in road transport

Ethanol3

Gasoline blends (E5, E10, E85 in FFVs), stoichiometry and materials
issues constitute blending walls in conventional vehicles
Additive treated ED 95 for diesel-type engines (commercial),
potentially also engines with assisted ignition (spark-plug, glowplug, dual-fuel)MethanolLow-level blends with gasoline
Heavy-duty engines as in the case of ethanol (additive treated fuel,engines with assisted ignition)

Various higher alcohols

E.g. butanol in gasoline blends

EthersE.g. MTBE (from methanol) and ETBE (from ethanol) in gasoline
blends, preferred by the auto manufacturers over ethanol ormethanol as such; blending wall stems from stoichiometry

FAME/Biodiesel

Diesel blends (B7, B10, B20, B30), neat B100
Neat B100 typically requires some vehicle modifications

Drop-in hydrocarbons

Gasoline-type components with limited octane for blending
components
Paraffinic HVO and Fischer-Tropsch diesel, drop-in, up to 100%
substitution

MethanePassenger cars (mostly bi-fuel methane/gasoline vehicles)
Heavy duty vehicles with either mono-fuel or dual-fuel technology
On-board storage either as compressed biogas (CBG) for LD
vehicles or liquefied biogas (LBG) for HD vehicles
Application in shipping

Biofuels

Various types of bioliquids, including some “biocrudes” less stringent
fuel requirements than in the on-road sector

MethaneMainly dual-fuel engines, fuel storage in liquid form, currently fossil
natural gas, bio-methane could replace natural gas
Application in aviation

Liquid renewable fuels

3

Current regulation allows up to 50 % renewable components, very
stringent certification process, hydrotreatment (HEFA fuels),
synthesis and e-fuels potential routes to aviation fuels

Brazil: special case for ethanol, regular gasoline contains 27 % ethanol (E27), also hydrous ethanol (E100) on

the market, special vehicles flex-fuel/bi-fuel vehicles combing gasoline/ethanol with methane available

xi

The easiest way to introduce biocomponents is to operate within the framework of existing
standards for gasoline and diesel fuel. Typically, standards allow blending of ethanol and
FAME biodiesel corresponding up to an energy share 10 - 15 %. Some activities to introduce
intermediate ethanol blends (E20, E25) are under way. However, for higher substitution andmore substantial decarbonization of transport, complementary actions are needed.
Drop-in type fuels are fully fungible with conventional hydrocarbon fuels and compatible withexisting vehicles and fuel infrastructure; no infrastructure or vehicle modifications areneeded. Paraffinic renewable diesel fuel, whether from hydrotreatment of oils and fats (HVO)
or Fischer Tropsch synthesis, can in principle completely substitute fossil diesel and for mostperformance criteria is superior to regular diesel.
B100 is not a real drop-in type fuel, as it requires some changes in calibration, engine
hardware and maintenance schedules. Notwithstanding, some heavy-duty vehicle
manufacturers allow the use of B100 fuel in present-day sophisticated vehicles.
In the case of gasoline, there are no superior renewable hydrocarbon drop-in components,
as bio-gasoline hydrocarbon compounds tend to have low octane numbers. New blending
components, such as pure hydrocarbons, higher alcohols or ethers, could alleviate this.
Finally, special fuels can be used as such or as high blends in dedicated or adapted
engines. Such fuels are, e.g., gaseous fuels (methane, LPG), dimethyl ether (DME) and highconcentration alcohol fuels (E85, ED95). These fuels have a merit in chemically simple
structure, and in most cases, also inherently clean burning. However, the market introductionof such fuels has to go hand in hand with building up the refueling infrastructure and thevehicle fleet, requiring huge joint efforts.
The world population of natural gas vehicles exceeds 20 million units. Cleaned biogas,
biomethane, is a drop-in substitute for natural gas. Ethanol flex-fuel vehicles (FFV) are still
offered for the markets in North and South America, but have in practice vanished from theEuropean market. FFVs are a cost-effective way of enabling the use of high concentration
ethanol.
Regardless of the method to introduce biofuels, whether low-level blending, drop-in fuels or
special fuels for dedicated vehicles, fuel quality, vehicle/fuel compatibility and vehicle
compliance have to be maintained. Prerequisites are standards defining and securing fuelproperties and vehicles adapted to and certified for the fuels they are using. The fuel issimply not a parameter that can be decoupled from the rest of the system, which comprisesof engine, lubricant, exhaust after-treatment system, refueling infrastructure and regulation
regarding safety and emissions.
xii

Authors
This report constitutes Part 2 of the final report on the project “The Role of Renewable
Transport Fuels in Decarbonizing Road Transport”, which was initiated and carried out
jointly by IEA Bioenergy and the Advanced Motor Fuels (AMF) TCP, with financial support of
the European Commission. The project was Task 41 Project 10 under IEA Bioenergy andAnnex 58 under AMF.
Participants in this project were the Contracting Parties of IEA Bioenergy from Brazil, theEuropean Commission, Finland, and USA, the Contracting Parties of AMF from China,
Finland, Germany, Japan, Sweden, and USA, and AMF Annex 28 and AMF Annex 59.
Further to this part “Production Technologies and Costs”, the following report parts havebeen published:•

Key Strategies in Selected Countries•

Scenarios and Contributions in Selected Countries•

Deployment Barriers and Policy Recommendations•

Summary Report

This report part was written by Lars Waldheim (Waldheim Consulting), Adam Brown (Energy
Insights Ltd), Mahmood Ebadian, Jack Saddler (both University of British Columbia), NilsOlof Nylund and Päivi Aakko-Saksa (both VTT Technical Research Centre of Finland Ltd)and edited by Dina Bacovsky (BEST – Bioenergy and Sustainable Technologies GmbH).
The IEA Bioenergy TCP is an international platform of cooperation working in the frameworkof the IEA´s Technology Collaboration Programmes. IEA Bioenergy’s vision is to achieve asubstantial bioenergy contribution to future global energy demands by accelerating the
production and use of environmentally sound, socially accepted and cost-competitive
bioenergy on a sustainable basis, thus providing increased security of supply whilst reducing
greenhouse gas emissions from energy use.
www.ieabioenergy.com
The Advanced Motor Fuels (AMF) TCP also is an international platform of cooperation
working in the framework of the IEA´s Technology Collaboration Programmes. AMF´s vision
is that advanced motor fuels, applicable to all modes of transport, significantly contribute to asustainable society around the globe. AMF brings stakeholders from different continents
together for pooling and leveraging of knowledge and research capabilities in the field ofadvanced and sustainable transport fuels.
www.iea-amf.org
xiii

Content
Introduction .......................................................................................................................... 9
Low-carbon fuel technologies and their development status .............................................. 11
Overview of regulated fuel qualities ................................................................................. 13
Technology pathways and status..................................................................................... 16
Established biofuel pathways ....................................................................................... 19
Ethanol from sugar and starch crops ........................................................................ 19
Biodiesel from triglycerides and lipids (FAME) .......................................................... 20
Hydrogenated triglycerides and lipids (HVO) ............................................................ 21
Biomethane from upgrading of anaerobic digestion biogas ...................................... 23
Emerging biofuel pathways .......................................................................................... 25
Ethanol from lignocellulosic feedstocks .................................................................... 25
Gasification to synthesis gas and fuel production ..................................................... 26
Pyrolysis to bioliquid intermediates ........................................................................... 28
Hydrothermal liquefaction (HTL) to bioliquid intermediates ....................................... 30
Lignin to bioliquid intermediates ............................................................................... 31
Sugars to biofuels..................................................................................................... 32
Non-lignocellulosic biomass ..................................................................................... 34
Low-carbon transport fuels from fossil waste sources .................................................. 35
Steel industry & chemical industry off-gases ............................................................ 35
Waste plastics and the fossil fractions of wastes ...................................................... 36
Low-carbon transport fuels from other forms of renewable energy ............................... 37
Hydrogen.................................................................................................................. 37
E-fuels (aka PtG or PtL) ........................................................................................... 38
Availability and costs of sustainable bioenergy feedstocks ................................................. 40
Potential feedstocks and costs ........................................................................................ 41
Municipal Wastes ......................................................................................................... 42
Processing residues ..................................................................................................... 43
3

Collectable residues ..................................................................................................... 43
Internationally traded fuels ........................................................................................... 44
Energy crops................................................................................................................ 44
Price versus costs ........................................................................................................... 45
Future Feedstock Cost .................................................................................................... 45
Summary – costs ............................................................................................................. 50
Feedstock availability ...................................................................................................... 51
Global estimates .......................................................................................................... 51
Information at national and regional levels ................................................................... 58
Biomass availability and costs in USA ...................................................................... 59
EU – S2Biom Study .................................................................................................. 59
Amounts of feedstock in Brazil ................................................................................. 60
Conclusions ..................................................................................................................... 61
GHG emissions of emerging biofuels pathways ................................................................. 63
Current GHG emissions of Renewable Transport Fuels .................................................. 63
Future GHG emissions of Advanced Renewable Transport Fuels ................................... 69
Role of policy on production and use of emerging biofuels ................................................. 72
Current biofuel production volumes ................................................................................. 72
Policies to increase biofuels production ........................................................................... 76
Summary of the role of biofuels policies .......................................................................... 81
The likely costs of emerging biofuels production and the scope for cost reduction ............. 82
Background ..................................................................................................................... 82
Current Production Costs ................................................................................................ 83
Potential for cost reduction .............................................................................................. 86
Medium term cost reduction ......................................................................................... 87
Long-term cost reduction ............................................................................................. 89
Importance of feedstock costs ......................................................................................... 91

4

Benchmarking costs ........................................................................................................ 92
Conclusions ..................................................................................................................... 92
Compatibility of fuels with existing engines ........................................................................ 94
Introduction ..................................................................................................................... 95
Reasons for limiting the concentrations of certain components ....................................... 98
Definitions for compatibility ............................................................................................ 100
Legislation, standards and recommended practices ...................................................... 101
Fuel quality marking for Europe ..................................................................................... 107
Examples of vehicle adaptation to special fuels ............................................................. 109
Effects of biofuels on tailpipe emissions ........................................................................ 111
Additional information on fuel properties, performance and vehicle compatibility ........... 114
Summary ....................................................................................................................... 116
Abbreviations ................................................................................................................... 119

5

List of Figures
Figure 1: Overview of technology pathways and their technology readiness level (TRL) ..... 18
Figure 2: Projected annual global supply for primary biomass in 203035.............................. 46
Figure 3: Typical cost ranges for biomass feedstocks ......................................................... 50
Figure 4: Summary of global biomass energy supply potential estimates in 2030 ,,,,,,,,,,,,,,,,, .... 52
Figure 5: Potential global biomass supply in 2030 (Adapted from IRENA, 2014) ................. 54
Figure 6: Breakdown of biomass supply ranges by regions (Europe includes Russia), 2030.
Two columns for each region represent the high and low supply potentials. ....................... 55
Figure 7: Factors that will contribute to the annual growth in the world’s potential biomass
supply by 2030 71 ................................................................................................................ 57
Figure 8: The carbon intensity values of current fuel pathways certified under the California
LCFS program Renewable Diesel is HVO/HEFA biofuels. .................................................. 66
Figure 9: Minimum, average, and maximum carbon intensity (CI) values of some of the fuelpathways certified under California LCFS program in 2019 ................................................. 67
Figure 10: Summary of LCA values derived from oleochemical and lignocellulosic pathways
to produce conventional and advanced drop-in hydrocarbons from various feedstock types68
Figure 11: World biofuels production from 2007 to 2017. Biofuels production increased at anannual growth rate of 11.4%, from over 37 Mtoe in 2007 to over 84 Mtoe in 2017 (Adaptedfrom BP, 2018) .................................................................................................................... 73
Figure 12: Technology-push and market-pull biofuel policies. Countries that use a mixture ofmarket-pull and technology-push policy instruments have been most successful atincreasing biofuels production and use and also at developing and deploying less matureemerging biofuels production technologies. ........................................................................ 77
Figure 13: Alternative low-carbon fuel volumes used in California ...................................... 78
Figure 14: The market value of cellulosic ethanol in California in 2016 and 2018 ................ 79
Figure 15: Summary of current cost ranges ........................................................................ 86
Figure 16: Potential costs of biofuels production after reductions ........................................ 89
Figure 17: Examples of impact of learning in costs with increasing learning rates ............... 90
Figure 18: Cost of feedstock in the overall cost of production.............................................. 91

6

Figure 19: Prerequisites for technical compatibility, and in the end, consumer acceptance. 98
Figure 20: Current European fuel standards7. ................................................................... 102
Figure 21: The new fuel labelling system for Europe28. .................................................... 108
Figure 22: Actual photos of fuel markings (truck fuel tank and fuel dispenser). ................. 109
Figure 23: Flex fuel vehicle features. ................................................................................. 110
Figure 24: Fuel effects on tailpipe emissions of light-duty vehicles. ................................... 113
Figure 25: Fuel effects on tailpipe emissions of heavy-duty vehicles33. ............................. 113

7

List of Tables
Table 1: Summary of sustainable biomass resources ........................................................ 58
Table 2: Greenhouse gas emissions savings thresholds in RED II ..................................... 64
Table 3: Renewable fuel categories under the RFS program, (US EPA, 2017a; Gottumukkala
and Hayes, 2018)................................................................................................................ 65
Table 4: Summary of current production cost ranges. ......................................................... 85
Table 5: Potential costs of biofuels production after reductions in EUR/GJ ......................... 88
Table 6: Application of transport fuels ................................................................................. 97

8

Introduction
Since the early 2000s, renewable transport fuels have been introduced in many countries
around the globe. Biomass is a renewable source of carbon and its use for bioenergy andbiofuels contributes to a circular economy. Biofuel production not only produces biofuels but
also valuable by-products, and provides value to the local biomass producers.
While ethanol and biodiesel are the main biofuels so far, also other biofuels have come into
focus recently, the most recent development being the introduction of e-fuels which may or
may not be based on biomass. The term “renewable transport fuels” is used to cover allthese alternative fuels.
Renewable transport fuels can be produced from many different feedstocks and through amultitude of conversion processes, and this causes large variations in the production costs
and the associated well-to-tank greenhouse gas emissions. Also, some of these fuels can beused in internal combustion engines just as they are, while others need to be blended withfossil fuels, or need to be applied in adapted engines. Given this large variety, policy makers
find it difficult to determine those fuels that would offer the most benefit to their societies
while being technically and economically feasible and compatible with their legacy fleet.
Also, large-scale deployment of renewable transport fuels will have effects on their costs andsustainability and thus constantly change the picture:•

increasing demand for certain feedstocks will cause a rise in feedstock costs;•

increasing demand for certain feedstocks may cause that they have to be sourced
from less sustainable production areas, resulting in smaller greenhouse gas emission
reductions;•progress in production technologies will reduce both the capital and the operating
costs

•

infrastructure costs for dedicated vehicles and fuel stations will be more easily offset
the larger the scale of their market introduction is.

This report provides the combined latest knowledge of IEA Bioenergy Task 39 and theAdvanced Motor Fuels TCP on the production and use of alternative motor fuels. It aims toprovide a sound basis for policy makers to take informed decisions with respect to thedeployment of renewable transport fuels.

9Terminology used in this report
In this report a distinction is being made between established biofuel pathways andemerging biofuel pathways. This is to avoid terms like first and second generation, 1G,
2G, conventional and advanced, as these terms have no homogeneous definition and areused differently in different regions and jurisdictions. Further fuel types mentioned in thereport include recycled carbon fuels and e-fuels. Further descriptions of these categories areprovided in Figure 1 and the explanatory text below.
The same figure also provides the linkage between fuel production pathway, i.e. feedstockand conversion technology used, and the chemical nature of the resulting fuel. When appliedin engines it is the chemical composition of the fuel that matters, not the feedstock. Thus,
some fuels are grouped, e.g. FT-liquids and HVO4 into drop-in hydrocarbons5.
The linkage between these fuels and the marketed fuel qualities is provided inTable 6, which also describes the applicability of these fuel qualities in different engines.

4

HEFA (Hydroprocessed Esters and Fatty Acids), also called HVO (Hydrotreated Vegetable Oil), is a renewablediesel fuel that can be produced from a wide array of vegetable oils and fats. The term HEFA or HVO is usedcollectively for these biogenic hydrocarbon-based renewable biofuels. HVO is free of aromatics and sulfur andhas a high cetane number.
5“Drop-in” biofuels are defined as liquid hydrocarbons that are oxygen-free and functionally equivalent topetroleum transportation fuel blendstocks.

10Low-carbon fuel technologies and their development status
Low-carbon transport fuels can be manufactured from:•biogenic feedstocks or biogenic fraction of wastes (“biofuels”)•

energy and carbon contained in fossil wastes and residue streams or the fossil
fraction of such materials (“e.g. recycled carbon fuels”)•

energy from other renewable sources, sometimes in combination with carbon
atoms from biogenic and fossil sources (CCU) (“e-fuels” or “renewable fuels of
non-biological origin”)

The technology readiness levels (TRL, see below) of the production technologies forthese fuels vary.
Technologies for the production of established biofuels such as ethanol from sugar andstarch crops, biodiesel from triglycerides and lipids, hydrogenated triglycerides and lipids,
and biomethane from upgrading of anaerobic digestion biogas are at TRL9.
Emerging biofuel pathways include ethanol from lignocellulosic feedstocks, gasificationderived biofuels, pyrolysis-derived intermediates, hydrothermal liquefaction-derived
intermediates, lignin-derived intermediates, sugars to biofuels, and biofuels derived from
non-lignocellulosic biomass such as microalgae. TRLs for these technologies range from
3 to 8.
Recycled carbon fuels include ethanol, methanol and methane produced from industry
off-gases, and fuels derived from the gasification or pyrolysis of non-biogenic wastes or
fractions of wastes, with TRLs ranging from 4 to 9.
E-fuels include hydrogen, methanol, methane and Fischer-Tropsch liquids. While theproduction of hydrogen via electrolysis is at TRL9, the other pathways are at TRL 4-6.
Terminology for different low-carbon fuels is not consistent globally. In the EU fuels areclassified by feedstock, in the USA by pathway. In particular the term advanced biofuel
has different meanings in different jurisdictions.

Based on the market application, low-carbon transport fuels can be classified as drop-in
fuels that can be blended into fossil fuels more or less without restrictions and also using theexisting infrastructure, e.g. HVO, low-blend fuels such as FAME biodiesel or ethanol blended
into diesel and gasoline up to a limited extent set by fuel standards (“the blendwall”), special
11

TRL scale
TRL 1 – basic principles observed
TRL 2 – technology concept formulated
TRL 3 – experimental proof of concept
TRL 4 – technology validated in lab
TRL 5 – technology validated in relevant environment (industrially relevant environment in
the case of key enabling technologies)
TRL 6 – technology demonstrated in relevant environment (industrially relevant environment
in the case of key enabling technologies)
TRL 7 – system prototype demonstration in operational environment
TRL 8 – system complete and qualified
TRL 9 – actual system proven in operational environment
fuels for dedicated vehicles, fleets and applications, e.g. DME, bio-gas for trucks or methanol
for ships, as well as additives with a biogenic fraction such as the octane enhancers MTBE
and ETBE that, apart of the energy provided, add to the functionality of the fuel.
Low-carbon transport fuels are in very general fuels manufactured from biogenic feedstocks
or biogenic fraction of wastes (“biofuels”), fuels manufactured by recycling of the energy andcarbon contained in fossil wastes and residue streams, or in the case of mixed biogenic andfossil materials, the fossil fraction of such materials (“e.g. recycled carbon fuels”), as well as
fuels produced using energy from other renewable sources, sometimes in combination withcarbon atoms from biogenic and fossil sources (CCU) (“e-fuels” or “renewable fuels of nonbiological origin”). Of all these options, only ethanol, biodiesel (FAME) and to a lesser extent
HVO are currently produced and used in significant quantities.
However, within these categories, there are a number of more detailed administrative
regulations in different jurisdictions that give more detailed definitions on the requirements
for different categories of low-carbon transport fuels in terms of eligible feedstocks andminimum GHG reduction requirements, determined by specific LCA methodologies.
For this reason, a specific conversion technology can yield differently defined fuel products
depending on which feedstock or energy source is used, if the conversion is a dedicatedfacility or by co-processing, or from the GHG reduction obtained.

12

Overview of regulated fuel qualities
In the EU6, there are “biofuels” “advanced biofuels” and “renewable liquid and gaseoustransport fuels of non-biological origin” and as of 2021 “recycled carbon fuels” and “biogas intransport”, the latter today being part of the “biofuels” and “advanced biofuels” categories.
There is a target for the Member States for renewable energy in transport, i.e. also including
renewable electricity with different multipliers, of 10% in 2020, to be increased to 14% in
2030. The obligated parties are the fuels suppliers in each Member State. Biofuels from“food and feed crops” (i.e. crops producing sugars, starch or vegetable oils) are since 2015
capped to 7%, this cap being maintained with some modifications in the period 2021-20307.
In addition, what is deemed as high iLUC feedstocks, e.g. palm oil, is subject by a delegated
act to further qualification to be an eligible biofuel. In addition, there is a cap of 1.7% for fuels
produced from feedstocks defined by Part B of Annex IX, used cooking oil (UCO) and certain
animal fats.
“Advanced biofuels” (also including some biogas for transport) are biofuels produced fromwastes and residues defined by Part A of Annex IX and has a separate target within theabove renewable energy targets of 0.5% and 3.5% in 2020 and 2030, respectively. The
Annex IX fuels, however, are counted at twice their energy content, if the Member States
decide to use this option. Optionally, the Member States may also decide whether to account“recycled carbon fuels” towards their respective targets.
The GHG reduction requirements for new “biofuels” and “advanced biofuels” installations are
60% at present to be increased to 65% in 20218. “Renewable liquid and gaseous transport
fuels of non-biological origin” will require 70% GHG reduction as of 2021 while themethodology and threshold value for “recycled carbon fuels” will only be set by theCommission via a delegated regulation in 2021. The LCA methodology is defined in thelegislation but a number of voluntary accounting and auditing schemes are also accepted
after verification and approval.

6 See the iLUC directive, (EU) 2015/1513, now in force and the RED II directive (EU) 2018/2001 coming into
force in 2021.
7

Defined as the minimum of 7% or the Member State actual consumption in 2020 of biofuels from “food andfeed crops” plus maximum 1%.
8

However, the absolute change in reduction is less, as the fossil comparator is increased in 2021 from thepresent 84 to 94 g CO2e/MJ.

13

At present, the Member States have implemented the EU-common directives in different
ways, by tax exemptions, quota obligations, blend obligations, GHG reduction obligations ortargets and trade certificate systems, and whether also to allow double-counting of theenergy value or not. Different approaches will probably be present also after the
implementation of REDII by the member states in mid-2021.
In the USA, the national policy to replace or reduce the quantity of petroleum-basedtransportation fuel, heating oil or jet fuel has resulted in a regulatory system, called
Renewable Fuels Standard9. The current second phase, RFS2, was initiated in 2007 andcontinues to 2022. The target is to overall have 36 billion gallons/year (136 million m3) ofdifferent renewable fuels in 2022, estimated to reduce the US GHG emissions by 138 million
tons. The system is administrated by the Environmental Protection Agency (EPA), whichsets annual Renewable Volume Obligations (RVO) for different fuel categories in advance,
to be fulfilled by the obligated parties, i.e. refiners and fuel importers.
These annual requirements are divided among different categories of biofuel classified by“pathways” from feedstock over conversion to certain types of fuels.
“Renewable fuel”, essentially crop-based (mainly corn-based) ethanol pathways, has at least
20% GHG reduction relative to the fossil fuel baseline on an energy basis.
“Advanced biofuel”, a subset of “renewable fuel”, is a renewable fuel other than ethanol
derived from corn starch and which meet a 50% GHG reduction threshold. Within the
category of “advanced biofuels” yet another two subcategories for specified feedstocks andconversion pathways are defined, “biomass-based diesel”, of at least 50% GHG savings,
and “cellulosic biofuel” of at least 60% GHG savings.
“Advanced biofuel” includes sugar cane ethanol and anaerobic digestion of certain wastes
but also fuels produced by the non-cellulosic fraction of biomass, e.g. lignin andhemicellulose, as well as hydrogenated diesel (HVO, see also below) produced in coprocessing with fossil fuels.
“Biomass-based diesel” includes FAME biodiesel and hydrotreated diesel (HVO) obtained
from e.g. vegetable oils (but not including palm oil), algae oils, animal fats, UCO, industrial
biogenic lipid residues and by-products greases, if produced in dedicated facilities (in thecase of co-processing see above).

9

www.epa.gov/renewable-fuel-standard-program

14

“Cellulosic biofuel” is fuel derived from lignocellulosic feedstocks e.g. forest and forest
industry residues (including lignin), agriculture residues and the biogenic portion of wastes
by either enzymatic hydrolysis, thermochemical conversion methods or anaerobic digestionof sludges, sorted wastes, manure but also of the cellulosic fraction of other wastes. In thecase of MSW that has undergone a recycling and separation process, EPA can on a caseby-case basis rule that the entire residual fraction, i.e. not only the biogenic fraction, isrenewable biomass.
Each of the renewable fuel categories are associated with tradeable certificates, Renewable
Identification Number (RIN) issued per gallon produced of renewable fuel (D3), advanced
biofuel (D4), biomass-based diesel (D5) and cellulosic biofuel, cellulosic ethanol (D6) andcellulosic diesel (D7), respectively. Refiners and importers have to provide RINs in relation totheir share of the fuel market to meet the overall volume and category targets. RINs areprimarily used to show compliance within its own category but can also for the category ofwhich it is a sub-set. Thus, D5, D6 and D7 can be used to show compliance for advanced
biofuels, D4, and in turn D4 can be used to show compliance for renewable fuels, D3.
General pathways to the various renewable fuel categories are analyzed and approved by
EPA and installations are audited to show that the actual production meets the requirementswith regard to the feedstock and GHG reduction.
The Californian LCFS system, introduced in 2009, aims to reduce the GHG emissions intransport by 20% in 2030. The LCFS sets annual carbon intensity (CI) standards, or
benchmarks, which reduce over time, for gasoline, diesel, and the fuels that replace them.
Fuels and fuel blendstocks introduced into the California fuel system that have a CI higher
than the benchmark generate deficits while credits are generated by fuels and fuelblendstocks with CIs below the benchmark and also from other projects in fossil upstream
and processing GHG reduction and infrastructure. Annual compliance is achieved when aregulated party uses credits to match its deficits, these being obtained by trading of credits.
A number of fuel production pathways have had their energy use and CI analysed, and there
are calculation tools available for a large number of bio-, fossil-, waste- and RE- based
pathways to transport fuels.
In Brazil, the support system RenovaBio has as its main objective to expand the biofuel
production in the country. This regulation considers the following biofuels categories: FAME
biodiesel blended into diesel, hydrous ethanol used as E100 and anhydrous ethanol blended
into gasoline as well as biogas and bio-kerosene. In addition, there are also blending
mandates for ethanol in gasoline and for biodiesel in diesel. The quantitative goal of theRenovaBio system is to gradually reduce the average GHG intensity in the Brazilian
15

transport system, which are equivalent, in 2030, to 90.7 million CBIO that shall be acquiredby the distributors. It is a certificate trading system (1 CBIO = 1 tonne CO2(eq)) that links
producers of biofuels (generators) with the fuel distributors (obligated parties). Authorized
institutions certify the production, and a LCA methodology is applied to ascertain the specific
GHG emission reduction. The difference between the LCA from fossil fuel and biofuels iscalled the environmental energy efficiency rate, which is multiplied by the certified productioncommercialized with distributors, resulting in the number of CBIO generated. Each distributor
has a reduction goal expressed as number of CBIO, which represents specific GHG
emissions reduction in their fuel pool. The carbon intensity of their pool, multiplied with theenergy of the fuels sold gives the number of CBIO to be rendered within the national CI
reduction target.
Below, in the sections dealing with specific types of biofuels, only the EU and US
classification of the fuels are mentioned. In California the classification is based on the
carbon intensity of the fuel rather than exactly which category of fuel is produced. In Brazil
biofuels are defined according to the feedstock, and the carbon intensity is used under the
Biofuels National Policy - RenovaBio.

Technology pathways and status
Figure 1 provides an overview on the various pathways for the production of low-carbon
transport fuels and on the technology readiness levels (TRLs) of these pathways. The main
pathways are briefly described in the following sections. For a more detailed description of
the technologies, their status and the cost of different biofuels, the references below provide
further information10, 11, 12, 13, 14.
From an end-use perspective, the above low-carbon fuel products can be classified as dropin hydrocarbons, low-blend fuels and special fuels. Drop-in hydrocarbon renewable fuels
include HVO diesel and HEFA kerosene as well as fuels produced via pyrolysis or HTL oils

10

SGAB Technology status and reliability of the value chains: 2018 Update. 28 December 2018. Ed. I Landälv, L

Waldheim, K Maniatis.
artfuelsforum.eu/news-articles/updated-sgab-report-technology-status-and-reliability-of-the-value-chains/
11

Advanced Biofuels – Potential for Cost Reduction. A. Brown et al. IEA Bioenergy: Task 41: 2020:01

12

ETIP Bioenergy

13

IEA Bioenergy TCP Task Groups in variety of topical areas, see www.ieabioenergy.com/our-work-tasks/

14

Global Potential of Biogas. World Biogas Association, June 2019.

16

and synthetic fuels (Fischer- Tropsch products) liquid intermediates, etc.. After upgradingthese fuels are fractionated to gasoline, diesel or kerosene products in various proportions.
These fuels in principle have similar properties and are to a large extent compatible with thegasoline, diesel and kerosene on the market and can be blended into these in a high ratio(typically well-above 10%), or in some cases even used neat. Low-blend fuels are ethanol,
other alcohols and oxygenates as well as FAME biodiesel, where the fuel properties arequite different from marketable fuels and therefore these renewable fuels can only be
blended into certain market fuels at a low blend rate, e.g. 10-20 % by volume ethanol ingasoline, 7% by volume of FAME, depending on local fuel specifications and vehicle OEM
acceptance. Special fuels (e.g. bio-methane, B100 FAME, E85, ED 95, DME, H2) are notcompatible with the ordinary liquid fuels market infrastructure or vehicles, and havededicated infrastructure and are used in vehicles specifically designed or adapted for the fuelin question (however in some case with dual-fuel capacity that also allows operation onconventional gasoline and diesel).

17

Technology Readiness Level (TRL)

Emerging Biofuels

Established biofuels

Raw material

Technology

Fuel

Fermentation

Ethanol

Transesterification

FAME/Biodiesel

Hydrotreatment

Drop-in hydrocarbons

Crops, sludges, manures etc.

AD biogas
upgrading

Biomethane

Raw material

Technology

Fuel

Enzymatichydrolysis +fermentation

EthanolLignocellulosic feedstocks

Sugar

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

1

2

3

4

5

6

7

8

9

StarchVegetable oils & lipid waste

Lignocellulosics , biogenic
fraction of RDF etc., nonlignocellulosic biomass or
by-products
Lignocellulosics , biogenic
fraction of RDF etc., nonlignocellulosic biomass or
by-products
Lignin from lignocellulosic
ethanol or forestry liquors

Other alcohols

Gasification +fermentation

Ethanol

Gasification +catalytic synthesis

Drop-in hydrocarbons,
Alcohols, Biomethane

Pyrolysis +upgradingDrop-in hydrocarbons

HTL + upgrading

Drop-in hydrocarbons

HTL and/or
chem. treatment+ upgrading

Drop-in hydrocarbons

Drop-in hydrocarbons

E-fuels

Recycle Carbon Fuels

Sugars from sugar andstarch crops or
lignocellulosic

Fermentation
Various alcohols
C hem. conversion

Drop-in hydrocarbons

Non-LC biomass fractions or
by-products

Various

Various

Supply of fossil waste or byproduct gases

Technology
Fermentation

Steel industry & chemicalindustry off-gases

C atalytic
synthesis

Gasification +Wastes, waste plastics, noncatalytic synthesis
bio fraction of RDF
or fermentation

Fuel
Ethanol
Methanol
MethaneDrop-in hydrocarbons,
Alcohols, Biomethane

Waste plastic fraction

Pyrolysis +distillation

Drop-in hydrocarbons

Supply of H2

Technology

FuelElectrolysis

Hydrogen
MethanolRE electricity

Electrolysis andcarbon capture+
catalytic synthesis

MethaneDrop-in hydrocarbons

Figure 1: Overview of technology pathways and their technology readiness level (TRL)18

Established biofuel pathways
Ethanol from sugar and starch crops
Sugar crops are predominantly sugar cane, but also sugar beets and sweet sorghum areused. These plants produce sucrose, a dimer of C6 sugars such as mainly glucose andfructose. By milling and leaching at slightly elevated temperatures the sucrose is extracted
into approximately 20 w% sugar juice, which is then pre-treated by clarification and a heat
treatment. A sugar mill may produce only sugar, only ethanol, sugar and ethanol in parallelon a more or less equal scale or mainly sugar and some ethanol from molasses(concentrated syrup residue after sugar crystallisation) only. Yeast and nutrients are injected
into the clarified juice and routed to fermenters where the sucrose is enzymatically split into
the C6 sugars and then fermented to alcohol (“beer”).
In the case of starch crops, mainly wheat, barley, corn (maize) but also e.g. cassava, theinitial step is dry milling the crop grains, separation of the starch “meal” and addition of waterand enzymes to obtain the starch as a thick gel slurry. There is also a wet milling process
where the grains are soaked in a dilute sulphuric acid solution prior to milling and recovery of
the starch, but also with possibilities for a range of valuable by-products. Starch is a polymerof C6 sugars - mainly glucose -, and enzymes are added to the slurry (“mash”) to
depolymerise the starch to release the sugars. The slurry is then heat treated and sent tofermenters where yeast and nutrients are added, and the sugars converted to alcohol.
The fermentation process takes 1-2 days to complete. In both cases (sugar crops, starch
crops), ethanol is recovered from the “beer” by a typically two-stage distillation to produce
approx. 94 w% ethanol hydrous ethanol (used as E100 in Brazil) followed by mol sieve
dehydration to reach above 99 w% minimum ethanol content (dehydrated or anhydrous
ethanol) for blending into gasoline.
In addition to ethanol (and sugar), by-products from cane ethanol are CO2 from thefermentation, bagasse fiber used as fuels and vinasse recycled as fertiliser. By-products
from the starch crop-based ethanol is in addition to CO2, dry distillers grain solids (DDGS)
used as cattle fodder and depending on the feedstock and milling technology, also technicalcorn oil, starch, syrup, gluten and bran. Due to increased requirements for GHG reduction
and also because it is a revenue-generating by-product from a waste stream, AD
technologies for residue streams are being more and more integrated into ethanol
production.
In the EU, ethanol from these pathways is a biofuel and is subject to a cap, in the USA it is arenewable biofuel.
19

The global production of bio-ethanol was 108 000 billion liters15 in 2018 (86 million tonnes,
638 TWh or 55 Mtoe, (tonnes of oil equivalents), of which over half was in the USA (some200 plants) and one quarter in Brazil (close to 400 plants16), an 5% in the EU (some 50
plants17), with no other country producing above 5%. The feedstock used is 46% corn, 38%
sugar cane, 5% wheat and then followed by molasses and other crops.
Biodiesel from triglycerides and lipids (FAME)
Biodiesel (FAME) is produced from vegetable oils, animal fats, used cooking oils (UCO),
greases and other fats and oils. Oils and fats mainly consist of triglycerides, i.e. three long
(C10+) and straight fatty acid chain molecules linked to a glycerol (aka propantriol, glycerine)
molecule via ester functionalities. The initial step in the FAME process is pre-treatment of thefeedstock which for vegetable oils is more or less similar to refining of edible vegetable oils.
Tallow, other waste lipids and UCO etc. also have other contaminants, in particular several
percent of free fatty acids (FFA) and must undergo additional purification before use. The
FFA is converted to FAME by acid esterification using methanol and sulphuric acid at
approximately 9 bar pressure and 125 °C. This can be made in an integrated process unit
upstream of the main conversion step or in a separate unit after separation of the FFA bystripping.
The pre-treated and purified triglyceride feedstock is processed by the transesterification
reaction with an excess of dry methanol at atmospheric pressure and 60 °C in several steps,
using a base catalyst18, commonly sodium methoxide or KOH, at residence times ofmagnitude of hours. The transesterification reaction results in that the glyceride ester isreacted with methanol (approx. 10%w of the triglyceride) to form three separate FAME
methyl esters and in exchange the glycerol is released into the reaction mixture. The
glycerol, (approx. 10%w of the triglyceride) is separated by gravity or centrifuges forrecovery. The separated crude FAME is treated by vacuum flashing or distillation to remove
the unreacted methanol, which is recycled, and by decanting to remove residual glycerol.
The crude FAME is then water-washed, followed by either vacuum-stripping or distillation toremove residual moisture and methanol and a final filtering step.

15

ethanolrfa.org

16

USDA Gains Report Brazil 201817

USDA Gains Report EU 201818

In addition, there are processes based on heterogenous catalysis and enzymatic reactions, but not incommon use at present.

20

Glycerol can be a valuable by product, the glycerol/water/salt/methanol mixture is subject totreatment to recover both methanol for recycling and a glycerol product19.
FAME biodiesel can be used as B100 but is more commonly blended into diesel, e.g. B7.
Since the FAME chemical process has not affected the structure of the fatty acid chains,these are still straight and retain any unsaturation originally present, but also traces ofglycerides that affects storage and use properties. For example, the choice of feedstock
dictates the cold flow properties via the original triglyceride composition and must therefore
be compatible with the climatic conditions of the intended market.
FAME biodiesel, subject to meeting the GHG reduction threshold, can in the EU be a biofuelor an advanced biofuel, eligible for double counting, depending on the feedstock used. Bothcategories can be produced in the same plant, if capable of using waste and residues
materials. In the USA, FAME, subject to meeting the GHG reduction threshold, is bio-based
diesel if eligible feedstocks are used.
Global production in 2017 was 36 billion liters20 (328 TWh or 28 Mtoe). In 2016, thefeedstock was 31% palm oil, 27% soybean oil, 20% rape seed oil, 10% UCO, 7% animal fat
and the balance other sources21.The EU (190 plants) is the main producer, 14 million liters
production and with 21 billion liters installed capacity22. The second largest producer is the
USA23 (124 plants) 7 billion liters in 2017 based on 9 million installed capacity. Number three
in production is Brazil (just over 50 plants) producing 5.9 billion liters but with 9.3 billion liters
capacity24, followed by Argentina and Indonesia providing 9 and 7 billion liters, respectively.
Hydrogenated triglycerides and lipids (HVO)
The HVO feedstocks are the same as for FAME biodiesel above, and the pre-treatment is inprincipal the same, with the exception that the HVO process can process FFA together withthe triglycerides. HVO type of biofuels can either be produced in stand-alone facilities, byconverting the existing oil refineries into HVO production or in co-production facilities.

19

Glycerol products traded range from crude glycerol (typically 80% glycerol) to pharmaceutical grade (99.5-

99.7% glycerol)20

OECD‑FAO Agricultural Outlook 2018‑2027. Biofuels. OECD FAO 2018.

21

UFOP Report on Global Market Supply 2017/2018. Union zur Förderung Von Öl- und Proteinpflanzen e.V.

22

USDA Gains Report EU 201823

biodieselmagazine.com/plants/listplants/USA

24

USDA Gains Report EU 2018

21

The first stage, the so-called hydrotreatment, takes place at 3-5 MPa (5-15 MPa for coprocessing in fossil hydrotreater) pressure and at temperatures between 300 °C and 450 °C
over a catalyst in a trickle column reactor, to which hydrogen is added with the liquid feed.
The hydrogen is today mainly derived from fossil sources25, but in the future it could bederived from the bio-LPG produced in the process or from RE power.
Initially, hydrogen saturates any double bonds of the triglycerides followed by a cleavage tofatty acids and the hydrogenation (hydrogen removes the acid group oxygen as H2O) ofglycerol to propane (i.e. bio-LPG) and water. Finally, the fatty acids undergo a combinationof hydrogenation or decarboxylation (the acid group oxygen leaves as CO2), the reaction
split depends on the catalyst and operating conditions used. This results in straight chain
alkane hydrocarbons.
The second stage of hydroprocessing involves the catalytic isomerisation and cracking of thestraight chain alkanes, at 300-400 °C, the severity of which is dictated by the desired fuelproducts. This second step result is a mixture of straight chain, branched chain, and cyclic
paraffinic hydrocarbons at similar or lower average carbon number than the original straightchains. The change in the molecular structure of the hydrocarbons allows aligning theproperties to the specification of marketed fuels for the local climatic conditions. The various
desired hydrocarbons product fractions, e.g. HVO diesel and/or HEFA kerosene, gasoline
and naphtha fractions are then separated by distillation.
HVO diesel can in the EU, subject to meeting the GHG reduction threshold, be a biofuel oran advanced biofuel, eligible for double counting, depending on the feedstock used and bothcategories can be produced in the same plant, if capable of using waste and residues
materials. However, HVO resulting from co-processing with fossil fuels is not accepted as a
biofuel in all member states, e.g. Germany. In the USA, HVO is bio-based diesel if produced
in a dedicated facility and an advanced biofuel if produced by co-processing, subject toeligible feedstocks being used and meeting the GHG reduction threshold.
Global production in 2017 was 6.5 billion liters (65 TWh or 5.6 Mtoe). There are some over
25 plants worldwide26 including co-processing. The EU has 14 plants, including co-25

mainly produced via steam reforming of natural gas or refinery fuel gas

26

SGAB Technology status and reliability of the value chains: 2018 Update. 28 December 2018. Ed. I Landälv, L

Waldheim, K Maniatis. artfuelsforum.eu/news-articles/updated-sgab-report-technology-status-and-reliabilityof-the-value-chains/22

processing facilities, that in 2018 had 2 million liters production and 5 million liters capacity(some plants were being commissioned in 2018, and all co-processing capacity not being
fully used). There are at least three dedicated plants in the USA and China and one plant in
Singapore.
Biomethane from upgrading of anaerobic digestion biogas
Typical feedstocks for biogas production are agricultural substrates (e.g. corn or specificallygrown energy crops), manure, wet waste fractions from the agriculture and food industry
sector as well as sludges from e.g. water treatment works in both cities and industries. A
special case is recovery of landfill gas from waste landfills to prevent release of the methane
formed over decades into the atmosphere.
Pre-treatment of the material to be fed into the digester depends on the nature of thefeedstock but may involve removal of non-digestable materials (plastics, metals, glass, grit),
washing, milling, screening and pressing depending on the feedstock. All biomass fractions,with the exception of lignin, can be degraded by anaerobic microbes. For high fraction of or
dedicated lignocellulosic feeds, e.g. agricultural residues, a pre-treatment27 is in most cases
used to make the cellulose and hemi-cellulose better available for the bacterial degradation.
The pre-treated feedstock is fed to the digester, a sealed container, where it undergoes
decomposition in the absence of oxygen over a period of several days. This process cantake place at different operating temperatures, most commonly at 35-40°C (mesophilic) but
also at higher temperatures, 55-60°C (thermophilic), thereby increasing the rate of digestion.
Based on the constituents and consistency of the feedstock treated, an anaerobic digester
can be designed as a ‘wet’, ‘dry’, ‘liquid’ or ‘co-digestion’ system while there are many typesof reaction systems depending on the capacity and the nature of the feedstock. During thedigestion, the bacterial population in the digester decomposes organic compounds in several
steps (hydrolysis, acidogenesis, methanogenesis) to a mixture of almost equal parts ofmethane and CO2 with some trace gases, mainly nitrogen and hydrogen sulphide, the“biogas”, which is collected in storage tanks or inflatable domes.
For use as vehicle fuel or for grid injection, the CH4 content of the biogas must be increased(> 97% CH4) by removing most of the CO2 from the biogas. Furthermore, the gas has to bedried and different trace gases (H2S, siloxanes) removed. There is a variety of commercially27This pre-treatment might be enzymatic, chemical or physical and for dedicated lignocellulosic feeds fairly

comparable to the pre-treatment of lignocellulosic material for alcohol production.

23

available upgrading technologies (e.g. PSA or membrane separation, amine or pressurizedwater scrubbing).
The residues and waters after digestion contain dissolved organics and inorganics as well as
non-digested solids. Depending on the feed, these residues can have a value as e.g.
fertilizers or require other treatments prior to their disposal.
Upgraded biogas, i.e. biogas for transport, can in the EU, subject to meeting the GHG
reduction threshold, be or not be, eligible for double counting, depending on the feedstock
used and both categories can be produced in the same plant. In the USA, renewable natural
gas is for most feedstocks counted as a cellulosic biofuel or otherwise as an advanced
biofuel if produced in a waste digester, again subject to meeting the GHG reduction
threshold.
There is a total of close to 50 million of micro-scale digesters operating around the globe,
predominantly in China (84%) and India (10%) directly fuelling stoves and small furnaces28.
In addition, there are an estimated 132 000 small, medium or large-scale digesters (i.e. anapproximate range of 0.5 to 20 MW gas output), again predominantly in China (83%) but
also in Europe (13%), USA, India and Canada, but there is a rapid growth in these numbers.
The main application of the biogas is power and CHP using IC engines, 88 TWhe was
generated in 2016 (indicating a global biogas production of the order of over 300 TWh).
In recent years the upgrading of biogas to biomethane for use as transport fuel or for grid
injection has become a proven technology in larger scale installations (2-20 MW gas output).
Globally some 700 plants upgrade biogas to biomethane (a few also producing liquefied biomethane) predominantly in Europe, 77%, mainly in Germany but also in the UK, Sweden,
France and the Netherlands, , USA (7%), China (4%), Canada (3%) and a few in Japan,
South Korea, Brazil and India. The European production of biomethane amounted to 17
TWh29 (1.5 Mtoe) while in the USA it is around 4 TWh30. So, in general, this technology is at
TRL9, but when using agricultural wastes (straw) as the sole feed, there is one plant by
Verbio in operation and another one in construction in Germany. Verbio also bought the28

Global Potential of Biogas. World Biogas Association, June 201929

SGAB Technology status and reliability of the value chains: 2018 Update. 28 December 2018. Ed. I Landälv, L

Waldheim, K Maniatis.
artfuelsforum.eu/news-articles/updated-sgab-report-technology-status-and-reliability-of-the-value-chains/30

www.anl.gov/es/reference/renewable-natural-gas-database24

former Dupont cellulosic ethanol plant, see “Ethanol from lignocellulosic feedstocks”, andplans to convert it to bio-methane production in co-production with corn-based ethanol.
Emerging biofuel pathways
Ethanol from lignocellulosic feedstocks
The term “lignocellulosic” feedstock includes agricultural and wood residues, wood fromforestry, Short Rotation Coppices (SRCs), and energy crops, such as some of the energy
grasses and reeds as their main structural material are cellulose, hemicellulose and lignin. It
also applies to waste fractions such as cellulosic fibers from cardboard and recycled paper.
Generally, unprocessed lignocellulosic biomass consists of 35–50% cellulose, 20–35%
hemicellulose and 10–25% lignin. Woody biomass has in general higher lignin content thanagricultural residues at the expense of the hemicellulose fraction while annual species(crops, grasses) have less lignin and are higher in hemicellulose. Cellulose is a crystalline
polymer of glucose forming the fibers in the plant material. Cellulose fibrils are surroundedby first a matrix of hemicellulose and then lignin in the secondary plant cell walls.
Hemicellulose is a more complex polymer of C5 and C6 sugars, often with a predominanceof C5 sugars. Lignin is also a polymer based on phenolic building blocks that provides
stiffness to the fibrils from external and “shields” these from biological and mechanicaldamage.
The first step in the processing of lignocellulosic feedstocks is a pre-treatment to fractionate
the feedstock into its three main components. The most common method is the steam
explosion with or without an acid catalyst but also acid and base treatment and organosolve
processes have been or are in use. The nature of the pre-treatment has large impact on theaccessibility of the still crystalline, de-lignified cellulose for saccharification while
hemicellulose is mostly hydrolyzed to sugars and oligomers and dissolves at this stage. The
lignin is not chemically altered and remain as a solid. The pre-treatment step also generates
different undesired components acting as inhibitors for the enzymes and yeasts,
respectively, used in the downstream process.
Additional water is added to the mixture of solids and liquids resulting from the pre-treatment
to reduce the viscosity after which hydrolysis and saccharification of the cellulose andhemicelluloses oligomers take place. This step uses specifically developed enzyme
cocktails, but also acid hydrolysis has been used. The enzyme treatment results in a viscoustwo-phase fluid. This fluid is either fermented in the same vessel (Simultaneous
Saccharification and Fermentation (SSF)) or in a downstream fermenter (Separate
Hydrolysis and Fermentation (SHF)). Lignin is separated before or after fermentation and25

usually dried to be used as a fuel for the process and/or for power generation. The celluloseand hemicellulose-derived C6 sugars are fermented by yeast strains derived from traditional
yeasts used for the production of wine, beer or bread, while for the fermentation of C5
sugars genetically modified yeasts have been developed in the recent years. After thefermentation has been finalized, the ethanol is recovered by distillation and dehydration as
described for sugar and starch ethanol above in the section “Steel industry & chemicalindustry off-gases
There is a complex trade-off between the water addition, the viscosity, the enzyme
consumption, the ethanol concentration achievable and the possible inhibition of the ethanol
and the energy required for the downstream processing. At present, the technology can giveup to 300 liters of ethanol per tonne of agricultural waste of which a significant part is derived
from the C5 sugars, i.e. an efficiency to biofuels of the order of 35% (assuming 5 MWh/t dry
substance).
Lignocellulosic ethanol is an advanced biofuel in the EU and a cellulose biofuel in the USA,however with the exception of the non-cellulosic portions of separated food waste and noncellulosic components of annual cover crops where the ethanol is an advanced biofuel.
There are, and also have been, a number of industrial developments worldwide forlignocellulosic (aka second generation) ethanol, many of which have reacheddemonstrations at TRL6. However, only a few of these developments have reachedindustrial scale at TRL8. In the last decade, six plants at industrial scale (25 000 90 000
tonnes/year product capacity each or 13 000-45 000 toe/year (toe, tonnes of oil equivalents)
have been built, one in the EU (Beta Renewables), two in Brazil (Raizen, Granbio) and three
in USA (Abengoa Hugoton, Dupont and POET Liberty). However, the Abengoa and Dupontplants are closed, the POET plant is back to R&D work, and the Beta Renewables plant wasclosed but has been taken over by Versalis who has announced that operation will beresumed. The Beta Renewables and the Granbio plants are based on the same technology
but different feedstocks, arundo donax and sugar cane bagasse, respectively.
Furthermore, there is one plant in construction in the EU by Clariant and others are being
studied, and in India the government has instructed oil companies to invest in twelve plants,of which a few plants are already under construction and others are in different stages ofplanning. These projects are based on both Indian (Praj, IBC) and foreign technologies.
Gasification to synthesis gas and fuel production
Thermal gasification is very fuel-flexible; it can in principle use any reasonably dry
combustible material as a feedstock. The feedstock potential for producing advanced
26

biofuels lies in forest and forest industry residues, agricultural and agro-industrial residues aswell as sorted municipal and industrial wastes (RDF31, SRF32, plastic wastes etc.).
Thermal gasification converts the combustible feedstock to a variety of products via
conversion to a gaseous intermediate, the synthesis gas, which is a mixture of mainly carbon
monoxide (CO) and hydrogen (H2). The fuel pre-treatment requires drying of the feedstock to
10-20% moisture, if necessary, and milling/shredding and grading to particle size suitable forthe type of gasifier used. In some cases, this may also involve some thermal treatment tofacilitate milling or conversion to a bioliquid slurry to increase energy density and facilitate
feeding. The pre-treated fuel is fed into the gasifier by mechanical devices in the case ofsolids or by pumping for liquids and slurries. In the gasifier, the fuel is converted to a raw
product gas using steam and oxygen, or by steam combined with indirect heating,respectively. Operating conditions are, depending on the process and type of gasifier (fixed
beds, directly heated fluidized beds, indirectly heated fluidized beds, entrained flow reactors)
from 800 up to 1 500 °C and pressures from atmospheric up to 3 MPa. The cleaning of the
raw gas constitutes of a series of process steps at temperatures starting from gasifier
temperature and going down to ambient temperature, and with integrated heat recovery.
These steps initially include removal of particulates, sulphur and other contaminants, as wellas catalytic adjustment of the hydrogen/carbon monoxide ratio, and in most cases also CO2
removal.
The technology for the use of the synthesis gas intermediate is well-established for fossilderived synthesis gas and has immense industrial importance for producing hydrogen in
refineries as well as many millions of tonnes of chemicals annually. Selective catalytic
chemical reactions convert the synthesis gas to, by choice, methane, methanol, DME orFischer-Tropsch hydrocarbons, respectively, at temperatures of 200 up to 400 °C. The
synthesis gas can also be converted to ethanol by micro-organisms at ambient temperature.
In addition, hydrogen as a product can be extracted directly from the gas.
Fischer-Tropsch hydrocarbon product is a mixture with a wide range of molecular weightsfrom LPG over naphtha and distillates to waxes. The waxes are typically hydrotreated andthen the combined liquid products are fractionated by distillation to gasoline, diesel and jet

31

RDF: Refuse derived fuel, the fuel fraction remaining after recyclable material and non-combustible waste

have been separated in a waste treatment facility however not associated with any specific quality measures.
32

SRF: Solid recovered fuel, an RDF where certain quality parameters and procedures have been defined, forfurther information see standard EN 15357 and standard in development ISO/DIS 21637.

27

fuel. Methanol and DME can, if desired, be processed further to gasoline. The typical energy
conversion efficiency (biofuel output energy/biomass feedstock energy as received) fromfeedstock to advanced biofuel products ranges from 40- 50% for drop-in hydrocarbon fuels
and 60-70% for gases and methanol.
In the EU, biofuels derived via gasification are advanced biofuels as far as they are
produced from biomass and biomass residues or the biogenic fraction of wastes, while in thelatter case the fossil fraction is a recycled carbon fuel. In the USA, the fuels derived frombiogenic materials and wastes are cellulosic biofuels, with the exception of the non-cellulosic
portions of separated food waste and non-cellulosic components of annual cover crops
where the fuel is an advanced biofuel. If the fossil part of wastes in a particular project is
exempted as biomass, see above, it is also part of the advanced biofuel produced, but
generally has no other benefits.
There are a number of TRL6+ pilot and demonstration plants in the EU and North America,
and the technology is fairly widely used for other purposes than biofuels, such as fuel gas
and power and heat. At present, only one advanced biofuel plant at industrial scale (TRL8) isin operation, the Enerkem plant in Edmonton, Canada, that produces methanol or ethanolfrom assorted wastes (RDF) at a nominal capacity of 24 000 toe/year. Up to 2018, also the
GoBiGas plant in Gothenburg Sweden was in operation, producing biomethane from forest
residue pellets up to a nominal capacity of 14,000 toe/year, but was closed for economic
reasons (lower than expected energy prices).
There are also two plants in construction in the USA, Red Rock Biofuels and Fulcrum Sierra
Biofuels that will both use the Fischer Tropsch process to produce hydrocarbons and mainly
bio-jet, 45 000 toe/year from wood residues and 33 000 toe/year from RDF, respectively.
Furthermore, there are two plants in planning using the Enerkem technology to produce
methanol from RDF, in Rotterdam, the Netherlands, at annual capacities of 102 000 toe/year
and Tarragona, Spain, at 123 000 toe/year, respectively. In California, Aemetis is planning a
23 000 toe/year ethanol plant using the InEnTec plasma gasification and the Lanzatech
synthesis gas fermentation technologies, see section “Steel industry & chemical industry offgases

Pyrolysis to bioliquid intermediates
Pyrolysis is the chemical decomposition of organic matter of biomass by heating in theabsence of oxygen. The feedstock decomposes into organic vapours, steam, noncondensable gases and char. The technology can in principle use any dry combustible
28

material as a feedstock. The feedstock potential for producing advanced biofuels lies inforest and forest industry residues, agricultural and agro-industrial residues as well as sorted
municipal and industrial wastes (RDF, SRF, plastic wastes etc.). The latter fuels with a highfossil carbon content will be discussed in section “Waste plastics and the fossil fractions ofwastes”.
The pre-treatment of the biomass feedstock typically includes drying to less than 10%
moisture and crushing/milling to particles of less than 5 mm. The highest yield of the desiredliquid fraction, up to 65%wt on a dry feed basis, is obtained by thermal fast pyrolysis. Fast
pyrolysis takes place in order of seconds at around 500 °C. The heating medium is typically
circulating sand, but also catalysts have been used. On cooling, the organic vapours and thesteam condense to a dark brown viscous liquid called fast pyrolysis oil (FPO) or sometimes
bio-oil. The char and gas are used internally to provide the process heat required, andadditionally also energy for export.
The word “oil” used in this context is misleading, the energy content is only half of that of fueloil, it contains ash solids, the oxygen content is almost as high as for biomass (35-40%), it isacidic and non-miscible with either conventional oil or with water. Nevertheless, this liquid istransportable, storable and can without upgrading to some extent be used as a fuel oil
substitute. By using a catalyst during pyrolysis or in the vapour phase, the oxygen content
and acidity of the oil can be reduced, at the expense of a lower mass and energy yield.
There is also a development of a pressurised pyrolysis in a hydrogen atmosphere, whereby
the bioliquid generated has a yet lower oxygen content and acidity and being more similar tohydrocarbon fuels. There are developments of the upgrading of pyrolysis oil, either in an
integrated facility at the production site or by co-feeding with fossil feeds at low blend ratios(a few %) in existing refineries.
A concept for the pyrolysis technology is where the intermediate product, the pyrolysis oil,can be produced at smaller capacity in distributed plants and the upgrading of the oil to dropin transport fuels is done in large plants fed by FPO from a number of such plants.
The main routes from FPO to a drop-in hydrocarbon biofuel is by fluid catalytic cracking(FCC) or by hydrodeoxygenation (HDO). In the case of the FCC route, oxygen is expelledfrom the FPO as CO and CO2 and the H/C ratio adjusted by coke formation to result in ahydrocarbon mixture where gasoline is the main fraction. The HDO route is basically atreatment with hydrogen whereby oxygen is expelled as water, this process having
similarities with the HVO process, see section “Hydrogenated triglycerides and lipids (HVO)”,and the resulting hydrocarbon mixture predominantly gives a diesel product. In both cases, a29lower yield of biofuel results from the mass loss, and also some energy loss in the case of
FCC, whereas the HDO treatment has a high energy yield based on the input biomassenergy, as energy from external hydrogen is consumed.
Another pathway combining these routes are an initial hydrotreatment to stabilize the FPO
followed by FCC treatment. The benefit is that both acidity and oxygen is reduced, and theblend ratio for co-processing can be increased significantly.
In the EU, biofuel derived via pyrolysis are advanced biofuels. In the USA, the fuels derived
from biogenic materials and wastes are cellulosic biofuels, with the exception of noncellulosic components of annual cover crops, where the fuel is an advanced biofuel.
The pyrolysis technology to produce an intermediate biooil, is demonstrated at TRL 8 by ahandful of Ensyn plants in North America over the last decade and more recently by BTG in
the Netherlands and Valmet/Fortum in Finland at capacities ranging from 10 000 -50 000
tonnes biooil/year, or approximately 4 000- 20 000 toe/year. However, this far, the primary
product is a replacement of fuel oil. Nevertheless, upgrading of such bioils to biofuels in
integrated plants or by refinery co-processing at percentage blends have been and is tested
at different scales, but mainly at TRL5-6 pilots. In 2018, Ensyn reported that they had a takeoff agreement for biooil intermediate with Valero, but specific details were not given. In late2019, the Pyrocell in Sweden announced the start of construction of a 25 000 tonnes/year
biooil plant co-located at a sawmill. The plant will be based on the BTG technology and thebio-oil off-take is for co-processing by the Preem Lysekil refinery, Sweden.
Hydrothermal liquefaction (HTL) to bioliquid intermediates
The hydrothermal liquefaction (HTL) process can treat lignocellulosic or other biomasses aswell as waste fractions. Lignocellulosic and other solid feeds must be pre-treated to allow theformation of a slurry at a reasonably high solid content by mechanical or thermomechanicalpre-processing such as e.g. steam explosion. On the other hand, wet fuels like sludges,
algae etc. can be processed without drying, which would be necessary for other thermal
processing methods.
Hydrothermal liquefaction (HTL) is a thermochemical conversion process of biomass(lignocellulosic or other biomasses) into a liquid intermediate by processing in a hot,pressurized water environment, typically 250 °C to 420 °C (but can be higher) and in apressure range is 4 MPa-30 MPa (i.e. both subcritical and supercritical conditions), forsufficient time (10-60 minutes) to break down biopolymeric structure to liquid and gaseouscomponents. The operating conditions are quite challenging, the feed must be turned into a
pumpable slurry, and this slurry and the liquids produced have an impact on the lifetime of30

pump, valves and construction materials, etc.
The HTL process usually produces four different product fractions, a gas phase, a solid
residue, a liquid aqueous phase and a liquid oily phase, i.e., bio-crude. The produced biocrude intermediate separates from water but still has 10-20% oxygen and still a relatively
high acidity. The HTL bio-oil has several more or less direct utilization routes e.g. low-blends
into bunker fuel, but it can also be upgraded as an integrated process step or by co-feedingin refinery units to produce drop-in biofuels. The upgrading technology for this type of oil is inprinciple similar to the upgrading of pyrolysis oil, see section “Pyrolysis to bioliquidintermediates”.
In the EU, biofuel derived via HTL processing of biomass residues and wastes are advanced
biofuels. In the USA, the fuels derived from biogenic materials and wastes are cellulosic
biofuels, with the exception of non-cellulosic components of annual cover crops where thefuel is an advanced biofuel.
Most of the research on HTL has been done in batch processes, but several technology
developers (PNNL/Genifuel, KIT, Aalborg University and Steeper Energy, Licella) havedeveloped continuous TRL 5 pilot systems. However, prototypes ranging from 4 000 up to
16 000 tonnes/year, say 3 000 to 12 000 toe/year are in construction for forest wastes(Canfor, Canada and Silva Green Fuels, Norway) and plastic wastes (ReNew ELP, UK) with
the intention to have off-site upgrading of the oil intermediate in fossil refineries.
Nevertheless, compared to pyrolysis technologies, the upgrading of the intermediate
bioliquid has not been tried to the same extent as for pyrolysis oil, such that overall, thetechnology when producing biofuels is at TRL4-5.
Lignin to bioliquid intermediates
Lignin, one of the three main components of lignocellulose and also one of few aromaticcompounds produced by plants, is a polymeric substance composed of phenolic monomers
that can be used as an intermediate for the production of biofuels. Lignin from pulping
processes is dissolved in the pulping (black or brown) liquor and currently used as a fuel inthe recovery boiler, where pulping chemicals are recovered for re-use. Such liquors can begasified by procedures discussed in section “Gasification to synthesis gas and fuelproduction” and the chemicals recovered. The pulping lignin can be withdrawn up to an
estimated 10-20% of the total amount with limited impact on the pulping processes. Pulping
lignin can be separated from the liquor by precipitation or by membrane filtration for further
separate treatment. An added advantage is that removal of a part of the lignin can allow ahigher pulp production as the capacity of the recovery boiler is often a process bottleneck.
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Hydrolysis lignin from lignocellulosic ethanol production is also a by-product and is available
as a solid after the pre-treatment or after fermentation, depending on the process
configuration. Today, it is also mainly used as a fuel for the internal energy demands of theprocess, plus some export energy, but could possibly be better valorized as a biofuel.
The processing of the separated lignin is in the liquid phase such that precipitated lignin is
dissolved. First, de-polymerization to phenolic mono- and oligomers is accomplished bychemical catalysis using bases or acids in combination with thermal or HTL processing
and/or hydrogen treatment. The oligomeric and monomeric substances, depending of thelevel of depolymerisation and nature of the components, are then dissolved in a fossil or a
triglyceride feed fraction or reacted via esterification with e.g. mixed fatty acids to allow
mixing with a fossil fuel fraction. Finally, the lignin-derived feed is co-fed to a refinery and ishydro-treated to remove oxygen and to produce cyclical aromatic or aliphatic hydrocarbons,depending on the process severity. The upgrading technology for this type of oil is inprinciple similar to the upgrading of pyrolysis oil, see section “Pyrolysis to bioliquidintermediates”.
In the EU, biofuel derived via HTL processing of biomass residues and wastes are advanced
biofuels. In the USA, lignin is not a feedstock listed in any approved pathway at present.
In Sweden, there are a few developments (Renfuel, RISE, Inventia, SCA and Suncarbon)
targeting lignin in or separated from black liquor, and a few pilot scale units at TRL5-6 arebeing implemented. This pathway still has to reach the demonstration phase, and only
Renfuel has this far disclosed plans for building a plant in Sweden consuming 25 000-30 000
tonnes/year of lignin and the intermediate to be co-processed by refiner Preem.
There are activities for recovering lignin from cellulosic ethanol plants, but the main focus ison bio-based materials rather than on biofuels, even if there are some activities aiming at
biofuels.
Sugars to biofuels
Isolated sugars, today from crop or starch sources but in the future possibly also fromlignocellulosic sources, is the starting point for a number of pathways to biofuels. There are
two types of processes, one involving engineered microorganisms and one via aqueous
chemical reactions.
The fermentation route involves different developments. Engineered yeasts can be used toferment sugar into a class of compounds called isoprenoids that have use forpharmaceuticals, nutraceuticals, flavours and fragrances and chemical intermediates, as
32

well as fuels. One of these isoprenoids is a 15-carbon hydrocarbon, beta-farnesene. It has
been hydrogenated to farnesane, a compound accepted for 10% blending in jet fuel as
Synthesized Iso-Paraffinic fuel, (SIP) in the ASTM D7566 standard. Another development isto produce butanols from sugars. Some bacteria naturally produce butanol and yeast can beengineered to produce butanol instead of ethanol. This pathway can be used for producing
both n-butanol and iso-butanol, the latter also having a high value as a chemical building
block.
A third development is to use an engineered microorganism to produce iso-butene that canbe the basis for chemicals but also oligomerized and hydrogenated to e.g. gasoline. Since
iso-butene is a gas that separates from the broth, this facilitates the product separation andupgrading, as well as limiting any product inhibition issues.
The second route is by chemical reactions called aqueous phase reforming (APR) that utilize
heterogeneous catalysts including zeolites, metals and noble metals at temperature andpressure (200 °C-250 °C, 3 MPa-5 MPa) to reduce the oxygen content of the carbohydrate
feedstock. This involves hydrodeoxygenation reactions that consume hydrogensimultaneously produced in-situ from the carbohydrate feedstock. The product from the APR
step is a mixture of chemical intermediates including alcohols, ketones, acids, furans andother oxygenated hydrocarbons as well as paraffins which can undergo further catalytic
processing using zeolites to generate a mixture of non-oxygenated hydrocarbons.
Yet another chemical pathway is to convert the sugars into specific platform chemicals, suchas Hydroxy-Methyl-Furfural (HMF), furfural or levulinic acid that can be further upgradedcatalytically to fuel blending components or hydrocarbons. However, this pathway ispreferably used at present to produce bio-based speciality chemicals rather than fuels.
This far, all developments at pilot scale have focused on cane sugar or crop starch, assugar-containing products produced via enzymatic hydrolysis of lignocellulose contains more
inhibitors and C5 sugars. However, at laboratory scale there are developments to develop
the tolerance of the microorganisms to widen the feedstock basis.
The biological technology that has reached the farthest is the Amyris technology to produce
farnesene from sugars, a plant in Brazil with a capacity of 40 tonnes/day (some 12 000
tonnes/year or approximately 12 000 toe/year) has been operated and part of the products
converted to bio-jet. However, the plant was sold to DSM and the Amyris and DSM activities
are now focusing on high-value chemical specialities rather than on fuel at present.
Other developers including Gevo and Butamax have used fermentation technologies to
produce iso-butanol at 5 000 tonnes/year (4 000 toe/year), and at 20 tonnes/year (1833toe/year) capacity, respectively. Both companies have plans for scale up at ethanol plants in
the USA. Global Bioenergies, a French company, has developed a fermentation technology
for producing iso-butene from sugars, and operates a 100 tonnes/year (108 toe/year)
demonstration facility in Germany. The company has announced plans for a first industrial
prototype in France. REG Life Sciences was pursuing a technology using bacteria to
produce fatty alcohols at pilot scale. The company was acquired from REG by Genomatica
in 2019, which may shift the product focus away from fuels. Overall, this pathway can besaid to be in the TRL 5-8 range.
Chemical conversion of sugars to hydrocarbons is pursued by e.g. Virent at up to TRL 5 pilot
scale.
Non-lignocellulosic biomass
Photosynthetic algae (including macro- and micro-algae) and photosynthetic cyanobacteria
have the potential to produce considerably greater amounts of biomass per hectare thanmost terrestrial crops and some species could even directly produce fuel (H2, ethanol oralkanes). Aquatic biomass can be cultivated using industrial carbon dioxide as carbon
source and wastewater as nutrient input (nitrogen and phosphorus), thereby not competingwith food crops for land or other resources. However, due to the large volumes of water
involved in the cultivation, nutrient balancing and recovery, as well as contaminant control
are essential for economic and environmental feasibility.
Large scale cultivation of microalgae in onshore, outdoor open pond systems and raceways
is well established but limited to a few algal species which can tolerate extreme
environmental conditions such as high salinity (Dunaliella), high pH (Spirulina (Arthrospira))or undergo extremely high specific growth rates (Chlorella). Closed cultivation systems for
microalgae, usually onshore, utilize photobioreactors made of transparent tubes, plates,bags or domes, which permit culture of single species at higher productivity than in open
systems. However, inhibition due to the oxygen formed is a scale-up issue and furthermore,
the prevention of intrusion of other competing species is also a challenge. Macroalgae(seaweed) are usually cultivated in offshore farms but their productivity is much lower thanthat of microalgae and may also have a seasonal growth pattern.
The typical microalgae concentration in cultivation broths is as low as 0.1-1% of total dry
suspended solids which requires an at least two-step recovery by thickening and dewatering
to reach a concentrate of 15-25% dry matter. To avoid degradation, the concentrate must be
dried. The harvesting and drying are very energy demanding and account for a large part of
total energy consumption, and methods for using e.g. waste or solar heat are pursued.
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Algae biomass composition consists of carbohydrates, proteins, lipids and other products
such as pigments, vitamins, etc., for use in food, cosmetics and other niche markets. The
lipids, up to 70% on a dry basis, have been the most interesting fraction for conversion into
biofuels. However, the extraction of the lipids requires energy-consuming methods forbreaking the cell walls. The lipids, once separated from the other components, can then be
converted to FAME and HVO, see sections “Biodiesel from triglycerides and lipids (FAME)”
and “Hydrogenated triglycerides and lipids (HVO)”.
In some cases, in particular for macroalgae, the cell walls are composed of carbohydrates
that can be hydrolysed and the sugars fermented to ethanol.
Also, HTL (see section “Hydrothermal liquefaction (HTL) to bioliquid intermediates”) of
aquatic biomass is being developed as this process can avoid the need for extensive
dewatering and drying. The entire algae biomass may also be used without or with limited
dewatering via anaerobic digestion to produce bio-methane, see section “Biomethane fromupgrading of anaerobic digestion biogas”. These two technologies are also considered forprocessing the algal biomass residues, once lipids and sugars have been recovered.
Algal-derived biofuels would be advanced biofuels in the EU, while there is no algal pathway
under RFS2 that has been approved by the EPA. Nevertheless, at present algal conversion
routes would have a problem of meeting the GHG reduction requirements, with the possible
exception of HTL and biomethane pathways.
During the last decade, there has been a number of developments at TRL 5 pilot scale tocultivate algae for production of bio-methane, lipids for FAME and HVO, as well as sugars
for ethanol, as described in the cited report33. However, the decrease in the energy prices in2014 have for most developers meant that the interest has shifted from fuels to high-value
chemical specialities, and the energy is more seen as a way of valorising biomass as
biomethane.
Low-carbon transport fuels from fossil waste sources
Steel industry & chemical industry off-gases
The feedstock for these processes is a variety of industrial waste gases that are today flared
or used for energy (power and/or heat) production in excess of what is used for the internal

33

SGAB Technology status and reliability of the value chains: 2018 Update. 28 December 2018. Ed. I Landälv, L

Waldheim, K Maniatis.

35

needs of the process from which they are emanating. Examples of such gases are cokeoven gas (COG), blast furnace gas (BFG) and basic oxygen converter gas (BOF gas) in thesteel industry, converter gas from production of alloying metals and refinery off-gases thatare similar to BOF gas. While coke oven gas and refinery fuel gases are rich in methane andother hydrocarbons, the other gases are very rich in CO but have low hydrocarbon content.
Such gases can be used to produce FT hydrocarbons or methanol after generating a gas
similar to synthesis gas, see section “Gasification to synthesis gas and fuel production”.
Gases with high hydrocarbon content are treated by steam reforming or partial oxidation to
generate synthesis gas. The catalytic conversion of CO rich gases requires that H2 isavailable in the synthesis gas in the correct proportions, which can be accomplished by awater gas shift reaction step consuming CO to produce H2. The gases are then cleaned tosynthesis gas quality by similar processes and then converted to fuels by the same type ofcatalytic reactions as was described in the cited section. There is one example of methanol
production from coke oven gas in China.
Another option is gas fermentation that can utilize gas streams with a wide range of CO andH2 compositions directly to produce ethanol, as the acetogenic microbes used are also
capable of an efficient biological water gas shift reaction. Furthermore, the gas purity
requirements are less strict than for chemical catalysis. The ethanol produced is thenseparated by distillation and dehydration as described in section “Ethanol from sugar andstarch crops”. A tail gas, including any hydrocarbons in the feed, unreacted CO and H2 notconverted as well as CO2 leaves the process. Some of the energy in the feed gas isconsumed to build microbial biomass in the system. The excess biomass can be used to
produce biogas via anaerobic digestion. The biogas together with the tail gas can be used tocover process energy needs.
Lanzatech have developed technology at TRL7, approaching TRL8, for CO or synthesis gas
fermentation which is being demonstrated at industrial scale, 45 000 tonnes ethanol/year(29 000 toe/year) in a steel mill in China using CO-rich BOF gas. A second plant is underconstruction in Belgium using a mixture of BOF and blast furnace gas at a capacity of 65 000
tonnes ethanol/year (42 000 toe/year), and there are also a number of other projects being
pursued, e.g. with Aemetis, for ferroalloy off-gas in South Africa and for refinery gas in India.
Waste plastics and the fossil fractions of wastes
Waste plastics, non-biogenic fraction of RDF etc. can, either separated or together withbiogenic fractions, be processed by thermal conversion and upgrading methods alreadydescribed above such as gasification, pyrolysis and HTL, and thus being at the same TRL
36

level. The Enerkem gasification developments were already described above in section“Gasification to synthesis gas and fuel production”.
One specific type of processing which has recently received a lot of attentions is theprocessing of separated plastic waste streams via pyrolysis or HTL systems. The pyrolysis
of waste plastics, mostly fractions or mixed fractions of polyethene, polypropene andpolystyrene, is mostly performed by slow pyrolysis at 400 °C in kilns or other types of
furnaces to render a mixed oil fraction, char and some gases, the latter used internally as afuel. The oil fraction from pyrolysis or from HTL processing can then be fractionated by
distillation to yield conventional hydrocarbon fuel fractions, in particular a diesel fraction. Thisis mostly done as an integrated part of the process due to legal requirements in the EU, but
could also be done in a refinery. Any liquid residue is recycled or used for energy in theprocess.
There are a number of such developments in the USA and the EU at a scale of 10 00040 000 tonnes/year. Some examples of developers with industrial scale plants in operation
and/or construction are IGE Solutions (NL), JBI (USA), Klean Industries (JP), Nexus Fuels(CN), Plastic Energy (UK), Quantafuel (NO), Recycling Technologies (UK), ReNew ELP(UK), Remondis (DE), Renewology (USA), and VADXX (USA).
Low-carbon transport fuels from other forms of renewable energy
In the EU, this refers to fuels that are produced using energy from other renewable energy
sources. In practice this means the use of renewable power from geothermal, solar or wind
power, where a local excess production can result during shorter or longer periods, thereby
giving access to such energy at low costs. There are also developments using e.g.
concentrated solar power or geothermal energy as a source for direct heat for use in fuelproduction.
Hydrogen
Production of hydrogen from renewable power is produced by means electrolysis of water inelectrochemical cells. Electrolyzers are composed of several cells arranged in “cell stack”
modules that can then be multiplied to reach the desired output capacity. The hydrogenproduced is then compressed or liquefied for storage.
Hydrogen production by means of alkaline electrolyzers has been around for more than acentury and is a fully commercial technology. Another technology that has more recently
been introduced is the so-called PEM (Proton Exchange Membrane), which is now
competing head-to-head with the alkaline electrolyzers. Other types (MCEC and SOEC,
37

molten carbonate and solide oxide electrolyzer cells, respectively) are still in development.
Electrolyzers installations have typically been up to a few MW in capacity, set by thehydrogen user’s requirements. However, with the increased use of wind and solar power
generation and also demand for hydrogen, and in particular renewable energy (RE)hydrogen, installations are growing in capacity to 10-20 MW and installations of 100 MW are
in planning and 1 000 MW installations are studied in the Netherlands
E.ON has a power-to-gas (PtG) pilot unit in Falkenhagen, Germany with an electrolyzer
capacity of 2 MW, the output mainly being injected to the gas grid, but also used by local
users. A second PtG pilot unit is in construction outside Hamburg to demonstrate a morecompact and efficient electrolysis equipment.
In addition, hydrogen form renewable sources can also be added to other biofuel conversion
pathways. One concept is a hybrid gasification-to-biofuel pathway. Hydrogen addition results
in process savings and a more efficient use of the biomass resources as the yield ofbiogenic carbon to fuel increases up to twice the amount without hydrogen addition34.
Renewable hydrogen can also be used in other pathways where hydrogen is used, e.g.
HVO, the upgrading of pyrolysis, HTL and lignin intermediate oils, thereby eliminating theinternal production of hydrogen in stand-alone biofuel plants or replace fossil hydrogen in
refineries. Another possibility is to add hydrogen to anaerobic digesters, and thereby
assisting in the methanogenesis step to produce additional biogas from the CO2 present.
E-fuels (aka PtG or PtL)
Electrofuels (E-fuels), Power-to-Gas (PtG) and Power-to-Liquid (PtL) refers to technologies,
which convert renewable electric energy to another energy carrier, like for example methane,methanol or synthetic hydrocarbon fuels via the Fischer Tropsch process.
In short, as a first stage, electricity is converted to hydrogen through electrolysis as
described above. To produce a hydrocarbon or alcohol fuel, a carbon source is also
required. This carbon source is typically CO2, which is readily available from many sources
e.g. biogenic CO2 from bakeries, ethanol fermentation in breweries or ethanol fuel plants, aswell as from biomethane upgrading or gasification plants, or fossil CO2 from, e.g. coal power
plant flue gases or industrial waste gas streams in e.g. refineries and chemical plants. Thisuse of CO2 is also often referred to as an example of Carbon Capture and Utilization (CCU).

34

Hydrogen enhancement potential of synthetic biofuels manufacture in the European context: A techno-

economic assessment, Hannula, Ilkka. Energy, Volume 104, Pages 199-212, 2016.

38

The production of fuels is essentially as described for gasification synthesis gas as
described in section “Gasification to synthesis gas and fuel production”. In the case of
production of biomethane or gas fermentation to ethanol, CO2 and H2 can be reacted
directly. For other products such as methanol and FT hydrocarbons, a reverse water gas
shift reaction is needed to convert CO2 to CO, prior to the catalytic synthesis process where
the products are formed.
The largest Power-to-Methanol facility is the CRI’s ‘George Olah’ Renewable Methanol Plant
with a capacity of 4 000 tonnes per year.
In addition, there are a number of pilot initiatives to produce methane (Audi/Solar fuels (DE),BioCAT (DK), methanol (MefCO2 (DE), Thyssen Krupp (DE)) and FT liquids (Sunfire (DE))
based on hydrogen from electrolysis at a scale of 1-5 MW electrolyzer capacity.
In general, these technologies are at TRL5-6, with the exception of the CRI plant at TRL8.

39

Availability and costs of sustainable bioenergy feedstocks
The theoretical availability and cost modelling indicate that large volumes of sustainable
feedstock could be made available for biofuels production, sufficient to meet likely future
demand as indicated in low carbon scenarios. Most of the material necessary could be
supplied from wastes and residues, and from sustainable forestry practices. Agriculture
can also be an important source of raw materials, with feedstocks produced in ways which
complement traditional agricultural production through co-cropping and through use ofless productive land.
Estimates of the potential available biomass and other uses vary significantly in theliterature. While the theoretical potential is high, the economic availability can vary greatly,
depending on numerous factors including yield and regional parameters (e.g. location andsize of crop/forest lands, local infrastructure, etc.). There is a wide range of biomass
availability globally, from as low as 95 Exajoule (EJ)/year to as high as 350 EJ/year.
National studies indicate that much of the raw material could be produced and delivered
to users at costs of between 3 - 6 EUR/GJ. More information from real projects is needed
to test the costs of procuring suitable feedstock in the real world.
The overall biomass cost is highly case dependent and successful management ofbiomass supply chains will be critical if future investments in biofuels are to be realized.
Despite efforts to reduce the cost of biomass and associated logistics, it is anticipated that
increasing competition for commercial quantities of biomass will result in an increase in
the price of the biomass feedstock.
National and regional assessments are very helpful in providing insights into likely longterm availability and costs of feedstocks for bioenergy production, including for the
production of emerging biofuels. However, in order to be useful for estimating long term
global availability such assessments need to be done in a very transparent way, with clear
classification of the various resources and of the assumptions made in defining how muchmaterial could in practice be available, and around the sustainability considerations
applied.
A useful step in harmonizing such approaches would be the development of some bestpractice guidelines for such studies, including some standardization and rationalization of
the classification of the various potential feedstocks, and of the sustainability constraints
which are applied. Such measures could facilitate the development of more consistent
resource estimates, which could be more easily compiled to give a global estimate, atleast for key producer and user regions.

40

Potential feedstocks and costs
Food crops such as corn, sugarcane and wheat are the primary feedstocks for the world’s
transportation bioethanol while vegetable oils such as rapeseed and soybean are currently
the primary source of feedstock for bio/renewable diesel 35. However, food security concernsand sustainability issues such as indirect land use changes (ILUC) have influenced biofuel
policies to encourage the production and use of low-carbon biofuels that will be produced
from lignocellulosic sources such as agricultural and/or forest residues36. A recent example
is the 2018 revisions made to European Union’s Renewable Energy Directive (RED),
referred to as REDII, to include solid biomass sustainability criteria and stricter biofuel
sustainability criteria as well as caps and quotas for the use of biofuels made from certain
feedstocks, see section “Overview of regulated fuel qualities”. Consequently, availability offood crops for the production of established biofuels on top of the current production is notassessed further in this report. The focus of the feedstock availability and cost will be on
biomass and lignocellulosic residues, which are shortly called “biomass” in the remainder ofthis section.
Many different biomass types may be considered as feedstocks for emerging biofuel
pathways. These can either be wastes, residues and by-products from other biomass-based
production processes or energy crops specifically produced with energy production in mind.
The feedstocks produced from wastes and residues for conversion to biofuels may beconsidered in four separate categories. 37 These are:•Wastes - materials which have no other useful purpose, and which otherwise have to
be managed, usually incurring a cost.

•

Processing residues and by products which arise part of an industrial process andare already available in quantity at a particular site (including for example sawdust to
be used for pellet production).

•

35

Locally collectable residues which are produced as part of a harvesting procedure,

Araújo, K., Mahajan, D., Kerr, R., Silva, M., 2017. Global Biofuels at the Crossroads: An Overview of Technical,

Policy, and Investment Complexities in the Sustainability of Biofuel Development. Agriculture, 7, 32;
doi:10.3390/agriculture7040032
36

Popp, J., Harangi-Rákos, M., Gabnai, Z., Balogh, P., Antal, G., Bai, A., 2016. Biofuels and Their Co-Products as

Livestock Feed: Global Economic and Environmental Implications. Molecules, 21, 285;
doi:10.3390/molecules21030285.
37

International Energy Agency (IEA), Paris, Technology Roadmap - Bioenergy for Heat and Power, 2012.

41

but which are dispersed, and which must be collected and brought to a central point
before they can be used, such as cereal straw, forestry residues.
•Internationally traded feedstocks, such as wood pellets, based on raw materials
available at an industrial site, which are extensively processed to improve the energy
density and then transported long distances to supply large scale conversion plants.

Municipal Wastes
Disposal of waste materials such as municipal solid wastes pose an increasing
environmental problem, especially in major cities, and is a major priority in rapidly growing
economies such as China and India. Finding disposal solutions such as landfill become
increasingly difficult and costly as volumes grow. Landfill is increasingly seen as
environmentally unsustainable due to impacts such as methane emissions and impacts onwater-courses. Solutions to minimise the problem include reducing waste generation,
reusing and recycling materials and making use of some fractions of the waste as afeedstock, including for energy production through combustion and CHP production. The
wastes are also being increasingly considered as a potential feedstock for biofuels
production. The material in its raw form is very heterogeneous and significant pre-processing
is needed to separate recyclable material (often required to reach recycling targets andrelated legislation and to produce a refuse-derived fuel which has a more closely defined
specification, before it can be used as a feedstock.
Using wastes such as the biogenic fraction of MSW as fuel or feedstock provides analternative disposal or environmental treatment option that avoids disposal costs at a landfill.
This environmental credit is often necessary to make energy projects economically viable,
because the difficult characteristics of the feedstocks require specific technologies with highcapital and operating costs, while the resulting fuel products are sold at general market
prices.
The credit available for removing materials from the waste stream depends on theenvironmental legislation in place. For example, the EU has an objective to move away fromlandfilling as part of its waste management directive, and has set targets for countries toreduce the wastes sent to landfill. This has stimulated countries to act. For example, the UK
has introduced a land-fill tax on materials sent for landfill, which has been increasing steadily
and now amounts to £91.35 (around 107 EUR) per ton of waste. This acts as a strong
incentive for other waste disposal methods which can offer a lower disposal cost. In othercountries, landfilling of combustible or organic wastes is prohibited by law, and incineration is
dis-incentivized by taxation, generating similar drivers. This means that waste can be42

available at a negative cost at the conversion plant in areas where waste management
policies and regulation are pushing a move to alternative waste disposal methods.
Some waste materials can acquire a value once there is a profitable use for them. For
example, Used Cooking Oil (UCO) and tallow have a traded market value when used forbiodiesel or HVO production. If conversion capacity exceeds the local availability of material,
then they acquire a scarcity value which can seriously affect the profitability of operation.
Securing long term waste feedstock supply contracts therefore is often a prerequisite before
such plants can be financed.
Processing residues
Many bio-based industrial processes lead to the collection and concentration of large
volumes of residues at the point of production. For example: the timber processing produces
large volumes of sawdust and other wood residues; pulp and paper production generates
black liquor; the sugarcane industry produces large volumes of bagasse.
If there are no existing uses for these materials, or an excess once internal energy needs
have been satisfied, they can be available at zero or low costs as the production andcollection costs of such materials have already been occurred as part of the original process.
However, such other economic uses are often possible and the materials acquire an“opportunity cost”. For example, saw mill residues can be converted into wood pellets.
Bagasse is the main source of energy for power and heat in the sugar mill, and isincreasingly used for high efficiency co-generation resulting in grid-export of power.
However, due to the use of mechanical harvesting increasing amounts of cane trash become
available as fuel replacement for bagasse. Costs for use at the site where they are to be
used typically range from zero to 15 EUR/MWh.
For process residues, the size of bioenergy plant operation may be limited by the availabilityof the raw materials, although this can be supplemented by bringing in additional materials
available nearby in some cases but increasing costs. (For example, bagasse in sugar mills isincreasingly being complemented by cane trash residues that were otherwise left in thesugar fields).
Collectable residues
These are materials produced during harvesting operations in agriculture or forestry that canbe collected and brought to a central point for conversion into energy. Given the cost ofcollecting, transporting and eventually storing of the biomass, the costs of the delivered
feedstock are increased since the collecting and transporting costs must be met by the user,
43

with typical costs of 4-8 EUR/GJ (15-30 EUR/MWh). Increasing the catchment area pushes
up the transport costs (and related CO2 emissions) and will thus limit the economic scale ofoperation of such plants, with a catchment area usually limited to around 50 km radius.
Internationally traded fuels
Finally, there is the prospect of pre-treating biomass to produce solid, liquid and gaseous
feedstocks with high energy density, suitable for international long-distance shipping for use
in large scale conversion plants. For example, wood pellets produced from sawmill residues,
are currently produced in several regions including Russia, British Columbia and theSouthern United States, and brought in bulk sea carriers to Europe for large scale power
generation. Given the attractive incentives in several European countries, many European
based utilities are actively developing supply chains all around the world. Currently suchtrade is motivated by incentives provided in European markets. Such fuels are compatible
with the large scales of operation which provide for more efficient power generation. Larger
plants will also be preferred for biofuels production in order to gain the economies of scaleassociated with larger conversion plants. Costs for such fuels may reach 30-45 EUR/MWh.
In the long run it is likely to be more economic to site conversion plants close to where large
quantities of low-cost feedstocks are available and to transport the finished fuel products,
which have higher energy densities and are easier to handle.
Energy crops
While crops such as sugar, corn or palm, which can be used for food or animal feed
production as well as a feedstock for biofuels production, it is also possible to grow crops
specifically for energy purposes. Examples are the production of miscanthus, short rotation
forestry (including poplar and willow) and crops such as jatropha (which contains an oil). In
these cases, all the production, harvesting, and pre-treatment costs must be met by the offtaker. Care must also be taken to avoid displacing food production, and to minimise any
negative direct or indirect land-use emissions (although moving from annual food crops toperennial energy crops may help improve soil carbon content).
To avoid competition with food production and to minimise associated land-use change
emissions, energy crops may be produced as part of a rotation scheme, thereby notaffecting the food and feed production of the same land. For example, trials show thatcarinata can be used as a “catch crop” produced between crops and improving soil carbon

44

levels.38 Alternatively crops can be produced on marginal land no longer in active use by
farmers, and can help to restore the quality of such abandoned land.

Price versus costs
The costs of some of these resources may be low, and early users of the materials as
feedstocks may benefit from this in terms of the prices they pay to producers. However, oncea market for the material starts to develop, and especially if there is potential for competition
between users for material, then the materials may acquire a higher value. For example, in
Europe a number of plants were built designed to use post-consumer waste wood (fromdemolition sites etc.) to produce electricity. The financial investment case was based on theassumption that the developers would receive a gate fee for the materials which would
otherwise have been sent to landfill. However, as capacity outstripped local supply, thewastes acquired a scarcity value and now commands a positive price, undermining the
profitability of the plants that had been built.
Developers tend to try and avoid such issues through careful siting of plants so that there isno competition for local resources, and by a long-term contracting strategy that locks insupply for an extended period. Companies also seek vertical integration of their supply
chain, so as to be in control of more elements of the supply chain. For example, the biopower group Drax in the UK have invested in wood pellet mills in the south of USA; Nesteand other HVO companies have acquired UCO collection entities; UPM are developing
energy crop supply chains in South America.

Future Feedstock Cost
It is apparent that potential biomass supply costs will be influenced by many factors such as
feedstock production costs, cost of harvesting and collection equipment, pre-processing
operations (e.g. grinding and drying), storage regime, transportation distances and modes,
etc. As summarized in Figure 2, the supply costs of biomass are a function of the total
annual global biomass supply, with projected amounts available in 2030. The supply
potential of each biomass component is summarized into two components: (i) the domestic
supply cost (in USD/GJ) and the domestic supply potential (in EJ/ year) (fully coloured
columns in the figure); and (ii) the related supply cost and the exportable volume (surplus)

38

UPM Carinata farms absorb carbon dioxide from the atmosphere, July 2019. https://www.upm.com/news-

and-stories/articles/2019/07/carinata-farms-absorb-carbon-dioxide-from-the-atmosphere/45

(hatched columns in the figure) if a region has export potential39.
Domestic biomass resources can be classified into three supply cost groups: (i) < USD 5 per
GJ (4.5 EUR/GJ)40 (low); (ii) USD 5-8 per GJ (4.5-7.3 EUR/GJ) (medium); and (iii) > USD 8
per GJ (7.3 EUR/GJ) (high). The low-cost group generally consists of processing residues
and wastes (e.g., bagasse, corn cobs, rice husk, wood processing residue, animal waste).
Feedstock costs can be zero for wastes which would otherwise have disposal costs or thatare produced onsite at an industrial installation (e.g. black liquor at pulp and paper mills orbagasse at sugar mills). The medium-cost group consists of harvesting residues (e.g., cereal
straw, corn stalk or other crop residues collected from the field) and the high-cost groupconsists mainly of energy crops and fuel wood. Although residues can be supplied at a
relatively low cost, if supply chains are well established, utilization is typically restricted toshort distances since transportation/collection costs are usually significant.

Figure 2: Projected annual global supply for primary biomass in 2030 35

39

The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand

projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf
40

1 USD= 0.9 Euro46

It has been estimated that the average, global cost of biomass is about USD 8.3 per GJ (7.5
EUR/GJ) (IRENA, 2014) with the cost of domestic biomass ranging from as low as USD 3
per GJ (2.7 EUR/GJ) in Africa (agricultural processing residues) to as high at USD 17 per GJ(15.5 EUR/GJ) for energy crops in more developed parts of the world. The amount ofexportable biomass available in regions with surplus biomass is estimated to be about 26%of the total global supply potential. However, the costs associated with transporting thisbiomass to different world regions are estimated to add an average of USD 3 per GJ (2.7
EUR/GJ) to domestic prices (from 0.5 via rail to USD 4 per GJ (3.6 EUR/GJ) via ship,depending on the distance and transport mode)39
Predicting ways to reduce biomass costs is challenging as numerous factors are involved
including the robustness of the local supply chain, resource potential, land availability,competitive industrial uses, sustainability criteria, etc.41. Thus, the overall biomass cost ishighly case dependent and successful management of biomass supply chains will be critical
if future investments in bioenergy and biofuel are to be realized. However, as covered in
more detail below, there has been considerable progress in several areas of biomass
handling such as improved mechanization for harvesting, collection and transportation of
biomass, efficient pretreatment of biomass and processing to energy dense products (e.g.
pellets) and the efficient use of road, rail and marine transportation of biomass over short-tolong distances. Other examples include:•

The forest industry reducing grinding costs of processing forest residues byimproving the efficiency and the fuel consumption of this operation. In some regionsof Canada, a grinding cost of 20 $CAD/dry tonne (dt) has been achieved ascompared to previous costs of $CAD25-30/dt (20-30% reduction in the cost of
grinding forest residues at the roadside)42,43. Ongoing research is looking into further
integrating forest biomass logistics systems with existing forest supply chains tofurther reduce biomass logistics cost.

41 IRENA, 2012. Renewable energy technologies: cost analysis series- Volume 1: Power Sector, Issue 1/5,
biomass for power generation. https://www.irena.org//media/Files/IRENA/Agency/Publication/2012/RE_Technologies_Cost_Analysis-BIOMASS.pdf
42 International Wood Markets Group Inc., 2014. Wood products business case options for the Fort Nelsonarea. Prepared for Northern Rockies Regional Municipality.
43 FPInnovations, 2017. Using FPInterface to estimate availability of forest-origin biomass in British Columbia:
Mackenzie TSA.

47

•

Development of “Best Management Practices for Integrated Harvest Operations in
British Columbia” to reduce the logistics costs and improve the quality of collected
forest residues44. For example, new truck configurations with higher Gross Vehicle
Weight (GVW) were introduced to reduce transportation costs. Another example isimproving the piling practices of forest residues at the roadside to reduce their ash
and moisture content. Good piling practices have also been shown to reduce theoperating costs of handling, grinding and loading of forest residues onto trucks.

•

The development and commercialization of new forest and agricultural equipment byOriginal Equipment Manufacturers (OEMs) such as Tigercat 845D equipped withspecialized biomass shear head, Tigercat 630D skidder with oversized grapple,
Peterson Precision whole tree chipper, Vermeer ZR5 self-propelled baler and Krone
pellet harvester have increased the operating capacities and reduce the logistics
costs of forest and agricultural biomass.

•

In 2010, the US Department of Energy, Bioenergy Technologies Office funded fiveprojects known as high-tonnage feedstock logistics projects to support AGCO
Corporation, FDC Enterprises, TennEra LLC, the State University of New York
College of Environmental Science and Forestry and Auburn University to work in
partnership with OEMs to develop commercial harvesting equipment for corn stover,switchgrass and woody biomass feedstocks. As of late 2014, all five US DOE BETOfunded high-tonnage feedstock logistics projects have been completed,demonstrating significant cost reductions ($US13/dt on average) for collecting,storing, and transporting biomass. Some of these technologies are alreadycommercialized.
Demonstrated cost reductions included45:o

AGCO Corporation: 29% reduction ($US51.54/dt to as low as $US36.75/dt)
for single-pass harvesting, high-density baling and modified truck trailers.

44 FPInnovations, 2018. Best Management Practices for Integrated Harvest Operations in British Columbia.
http://blog.fpinnovations.ca/blog/2017/09/18/a-new-guide-for-integrated-harvest-operations-in-britishcolumbia/
45

US Department of Energy (US DOE), Bioenergy Technologies Office 2014 accomplishments and successes:

Growing America’s energy future. Retrieved fromhttps://www.energy.gov/eere/bioenergy/bioenergy-technologies-office-2014-accomplishments-andsuccesses.

48

o

FDC Enterprises: 25% reduction ($US50.78/dt to as low as $US37.89/dt) for
self-propelled balers, high-density balers, self-propelled bale pickup trucks,
and self-loading/unloading trailersoTennEra LLC: 7% reduction ($US56.38/dt to $US52.34/dt) for field chopping,bulk handling, and storage.

•

In the area of feedstock development, improved energy crops that exhibit morefavorable chemical compositions and are easier to convert to targeted biofuels havebeen developed. Examples of transforming sugarcane and Miscanthus into better
feedstocks for producing biodiesel and biojet fuels include “engineering” these plants
to produce higher levels of oil (lipids) rather than sugar (carbohydrates). In February
2018, the US DOE awarded $10.6 million grant to the so-called ROGUE (Renewable
Oil Generated with Ultra-productive Energycane) project, a collaboration byresearchers from the University of Illinois, Brookhaven National Laboratory,
University of Florida, and Mississippi State University.

•

In the area of landscape design, techno-economic analysis carried out by Idaho
National Laboratory (INL) demonstrated that, by using integrated landscapemanagement (ILM) techniques, stakeholders could produce energy crops at costs
20% lower than previously obtained46.

•

Projected biomass feedstock costs in Europe (by 2020) suggest that reductions of
2% to 25% could be achieved for agricultural and forest biomass, with projections
that energy crops will be 5-10% cheaper as result of harvesting and logistic
improvements47.

With increasing demand for biomass for bioenergy and biofuels applications, it is anticipatedthat operating costs will continue to fall in parallel with improved quality of biomass delivered
to the gate of biorefineries. As previously discussed, transition strategies are alreadyunderway in the agricultural and forest equipment manufacturing industries, including boththe modification of existing equipment and the development of new equipment that will
harvest, collect, transport and process commercial qualities of biomass in a cost-efficient

46 Roni, M., Thompson, D., Hartley, D., Griffel, M., Hu, H., Nguyen, Q, N., Cai, H., 2018. Herbaceous Feedstock
2018 State of Technology Report. INL/EXT18-51654.
47 IRENA, 2012. Renewable energy technologies: cost analysis series- Volume 1: Power Sector, Issue 1/5,
biomass for power generation. https://www.irena.org//media/Files/IRENA/Agency/Publication/2012/RE_Technologies_Cost_Analysis-BIOMASS.pdf

49and effective manner. Such transitions will be critical if the world is to meet target cost andquality specification identified by the biorefineries that will produce sustainable, low costbiofuels48.
Despite efforts to reduce the cost of biomass and associated logistics, it is anticipated that
increasing competition for commercial quantities of biomass will result in an increase in theprice of the biomass feedstock. This has already been observed with the supply of usedcooking oil (UCO) and tallow. Both feedstocks are the waste streams of industrial operations
that used to be purchased by biofuel producers at zero/low cost. However, due to increased
demand for biofuels such as biodiesel and renewable diesel, the price of these feedstocks
has increased in recent years is some regions of the world. The cost and price of forest andagricultural residues has proven more variable with both positive (e.g. supply/logistic chain
cost reductions) and negative factors (e.g. increased competition for residues) influencing
these values49.

Summary – costs

Figure 3: Typical cost ranges for biomass feedstocks

48 Mann, M., Biddy, M., Augustine, C., Nguyen, Hu, H., Ebadian, M., Webb, E., 2019. Evaluation of agriculturalequipment manufacturing for a bio-based economy. Technical Report NREL/TP-6A20-71570.
49 E4tech, 2017. Ramp up of lignocellulosic ethanol in Europe to 2030. http://www.e4tech.com/wpcontent/uploads/2017/10/E4tech_ICLE_Final_Report_Dec17.pdf.

50

With increasing demand for biomass for bioenergy and biofuels applications, it is anticipatedthat operating costs will continue to fall in parallel with improved quality of biomass delivered
to the gate of biorefineries. However, increasing competition for commercial quantities ofbiomass will likely result in an increase in the price of the biomass feedstock, a trend thathas been observed for forest biomass for the production of wood pellets and used cooking
oils and animal fats for the production of biodiesel and renewable diesel.

Feedstock availability
Global estimates
There have been many studies which have attempted to quantify the potential supply of
biomass feedstocks for bioenergy use. The range of estimates varies by several orders ofmagnitude depending on the assumptions made. Key issues include the proportions ofvarious wastes and residues that could be used economically while complying withsustainability requirements, how much land might be used to produce energy crops, given
uncertainties around future food demand, regional parameters (e.g. location and size ofcrop/forest lands, local infrastructure, etc.), crop rotations, slope and soil type, length of theharvest window, collection rates, the presence of a local processor or aggregator, andcompeting uses (e.g. animal feed and bedding)50;51.
As summarized in Figure 4, there is a wide range of biomass availability globally, from as
low as 95 Exajoule (EJ)/year to as high as 350 EJ/year. This wide range in estimating thepotential availability of biomass is largely due to differences in the assumptions. The different
assumptions include land availability, global food consumption, yields and sustainability
considerations52. However, estimates of biomass availability have come closer in reports
published since 2010, primarily because more recent studies take into account sustainability
issues and resource limitations, as well as improved quality of data regarding land

50 IEA Bioenergy Task 43, 2017. Mobilization agricultural residues for bioenergy and higher value bio-products:
resources, barriers and sustainability. https://www.ieabioenergy.com/wp-content/uploads/2018/01/TR201701-F.pdf
51 E4tech, 2017. Ramp up of lignocellulosic ethanol in Europe to 2030. http://www.e4tech.com/wpcontent/uploads/2017/10/E4tech_ICLE_Final_Report_Dec17.pdf.
52 The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand
projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf

51

availability and yields.
IRENA (2014)53 estimated that total available global biomass supply will be in the range of
97-147 EJ/year by 2030 (in primary energy terms). About 38-45% of this total supply isestimated to be available from agricultural residues and food waste (37-65 EJ/year) with theremaining amount (60-82 EJ/year) shared between energy crops (33-39 EJ/year) and forest
biomass (27-43 EJ/year) (Figure 5). Although agricultural residues and wastes have thegreatest global potential, forest biomass is also important. Energy crops could account for
26-34% of the total supply potential, eventually becoming the dominant source of biomass

Global biomass supply (EJ/year)

for future biofuel projects54.

200

180
160
140

Energy Crops

120

Agricultural residues

Forest biomass

100
80
60

40
20
0

Figure 4: Summary of global biomass energy supply potential estimates in 2030
55,56,57,58,59,60,61,62,63,64,65,66,67,68,69,70,71,72

53 IRENA, 2014. Global bioenergy supply and demand projections. A working paper for REmap 2030.
https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf
54 The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand
projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf
55 IRENA, 2014. Global bioenergy supply and demand projections. A working paper for REmap 2030.
https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf

52

56 Fischer, G., and Scharttenholzer, L., 2001. Global bioenergy potentials through 2050. Biomass andBioenergy 20, 151-159.
57 Berndes, G., Hoogwijk, M., van den Broek, R., 2003. The contribution of biomass in the future global energy
supply: a review of 17 studies. Biomass and Bioenergy, 25, 1-28.
5858 Hoogwijk, M., Faaij, A., van den Broek, R., Berndes, G. Gielen, D., Turkenburg, W., 2003. Exploration of
the ranges of the global potential of biomass for energy. Biomass and Bioenergy 25, 119-133.
59 Smeets, E.M.W., Faaij, A.P.C., Lewandowski, I.M., Turkenburg, W.C., 2007. A bottom-up assessment andreview of global bio-energy potentials to 2050.Progress in Energy and Combustion Science 33, pp.56-106.
60 Smeets, E.M.W., Faaij, A.P.C., Lewandowski, I.M., Turkenburg, W.C., 2007. A bottom-up assessment andreview of global bio-energy potentials to 2050.Progress in Energy and Combustion Science 33, pp.56-106.
61 Field, C.B., Campbell, J.E. and Lobell, D.B., 2008. Biomass energy: the scale of the potential resource. Trends
in Ecology and Evolution 23 (2), 65-72.
62 Hoogwijk, M. and Graus, W., 2008. Global potential of renewable energy sources: A literature assessment.
Background report. Ecofys, Utrecht.
63 Dornburg, V., et al., 2008. Biomass assessment: Assessment of global biomass potentials and their links tofood, water, biodiversity, energy demand and economy. Netherlands Environmental Assessment Agency,
500102012, de Bilt.
64 Dornburg, V., et al., 2010. Bioenergy revisited: Key factors in global potentials of bioenergy. Energy &Environmental Science 3, 258-267.
65 WBGU, 2008. World in transition. Future bioenergy and sustainable land use. Summary for policymakers,
October 2008. German Advisory Council on Global Change, Berlin.
66 Erb, K-H., Krausmann, F., Lauk, C., Plutzar, C., 2009. Eating the planet: Feeding and fuelling the world
sustainably, fairly ad humanely – a scoping study. Social Ecology working paper 116, November 2009. Social
Ecology Vienna, Vienna.
67 Hakala, K., Kontturi, M., and Pahkala, K., 2009. Field biomass as global energy source. Agricultural and Food
Science 18, 347-365.
68 Gregg, J.S., and Smith, S.J., 2010. Global and regional potential for bioenergy from agricultural and forestry
residue biomass. Mitigation, Adaptation Strategies Global Change 15, 241-262.
69 Haberl, H., Beringer, T., Bhattacharya, S.C., Erb, K-H, Hoogwijk, M., 2010. The global technical potential of
bio-energy in 2050 considering sustainability constraints. Current Opinion in Environmental Sustainability 2,
394-403.
70 Haberl, H., et al., 2011. Global bioenergy potentials from agricultural land in 2050: Sensitivity to climatechange, diets and yields. Biomass and Bioenergy, 35, 4753-4769.
71 Beringer, T., Lucht, W., Schaphoff, S., 2011. Bioenergy production potential of global biomass plantations

53

Figure 5: Potential global biomass supply in 2030 (Adapted from IRENA, 201473)

When the bioenergy supply potential of six regions of the world are compared (Figure 6), thelargest potential supply is in Asia (43 EJ/year) and Europe, including Russia (36 EJ/year).
North and Latin America together account for another 45-55 EJ/year of the total supply.
Agricultural residues in Asia (6-16 EJ/year), energy crops in Latin America (~16 EJ/year) and
fuel wood in Europe (0.3-13 EJ/year) and North America (~3 EJ/year) account for a large
share of the total global biomass supply. Energy crops in North America (~7 EJ/year), Africa(5-7 EJ/year) and Europe (~7 EJ/year), as well as processing residues (4-10 EJ/year) andwaste (~8 EJ/year) in Asia are also important (IRENA, 2014).

under environmental and agricultural constraints. Global Change Biology Bioenergy, 1-14.
72 Lauri, P., Havlík, P., Kindermann, G., Forsell, N., Böttcher, H., Obersteiner, M., 2014. Wood biomass energy
potential in 2050. Energy Policy 66, 19-31.
73 The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand
projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf

54

Energy crops
Agricultural residues
Processing residues
Animal and food wastes
Fuel wood
Forest biomass

Figure 6: Breakdown of biomass supply ranges by regions (Europe includes Russia), 2030 74. Two columns foreach region represent the high and low supply potentials.

It is apparent (Figure 7) that various factors will influence the biomass supply potential
estimates. For example, biomass derived from energy crops will require considerable investments in infrastructure (production and logistics) and will have to compete with land required
to meet growing food and energy demand74. Latin America enjoys an advantage in this area
because of its current land availability, but North America is more challenged because of
anticipated domestic food and energy demand for any “surplus” land. It has been reported
that African regions have the largest volume of potentially suitable land to produce energy
crops. However, ongoing problems such as underdeveloped agricultural land, low
productivity, difficult transportation logistics, etc., will first have to be resolved74.
Fuel wood production using surplus forest areas will require the development of a robust
supply chain with the establishment of potential dedicated biomass plantations requiring
relatively long lead times, such as seven years for fast growing species such as
eucalyptus69. Considering the very uneven land distribution among countries, full deploymentof surplus land will only be achieved through expansion of international biomass (e.g. wood

74

The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand

projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf

55

pellet) and agricultural commodities trade. However, even if there is to be an increase intrade and the overall biomass market, various policy measures will be required such as
stable financial support measures for early stage of development, long-term policy targets toensure sustainable market opportunities, awareness-raising, pilot activities and thedemonstration and introduction of sustainability criteria, quality standards, technical support,
etc. 74.
It has been suggested that the amount of agricultural residues that might be available will bedirectly related to the volume of food/feed available as residues are typically generated inproportion to the amount of food/feed consumed74. The increase in food consumption has
been calculated to range between 0.8 and 2.4% per year based on Food and Agriculture
Organization (FAO) estimates75. If the world is to increase the harvesting of agriculture
residues, conventional farming systems will need to be modified to handle, efficiently andsustainably, both the primary commodities and the residues. These types of integrated
systems will also require an assessment from various perspectives, particularly theagronomic one, to ensure soil fertility while extracting a portion of the potential bioenergy
feedstock. This type of ‘integrated-approach” is already being pioneered in the US (cornand-corn stover) and Brazil (sugar-and-sugar cane bagasse)76.
For all biomass types, large-scale mechanized logistics systems will be critical since
competitive feedstock costs will be a key factor for any potential energy applications.

75 Food and Agriculture Organization, 2014. FAOSTAT- the Statistics Division of the FAO. FAO, Rome.
http://faostat.fao.org/.
76 The International Renewable Energy Agency (IRENA), 2014. Global bioenergy supply and demand
projections. A working paper for REmap 2030. https://www.irena.org//media/Files/IRENA/Agency/Publication/2014/IRENA_REmap_2030_Biomass_paper_2014.pdf

56

Figure 7: Factors that will contribute to the annual growth in the world’s potential biomass supply by 2030 71

In a recent work, a review of the literature carried out as part of the work for the IEA
Bioenergy Roadmap estimated the potential long-term availability of biomass sources (to2060), based on analysis of a wide range of studies at global level.77 The high-level results
are summarized in Table 1.
The conclusions that can be drawn from this analysis are that:•

While the costs of feedstocks based on MSW are lower than those of other raw
materials, global supplies are relatively limited and could not provide a substantial
proportion of likely future biofuels needs. In many places waste incineration withenergy recovery as power and also heat may be preferred to using the material as afeedstock for biofuel production.

•

Much larger supplies of wastes and residues from forestry and agriculture are likely
to be available which could provide the bulk of the raw materials needed for
emerging biofuels production.

•

There is considerable scope for raw material supply from agriculture, with anemphasis on crops that can be co-produced with food crops or using contaminated or

77

International Energy Agency (IEA), Technology Roadmap: Delivering Sustainable Bioenergy, 2017https://webstore.iea.org/technology-roadmap-delivering-sustainable-bioenergy

57abandoned land so as to avoid issues related to direct and indirect land-use change
emissions.
Table 1: Summary of sustainable biomass resources 78
SourceSustainability conditions

Resources (EJ)
2060

Municipal wastes

Taking account of the waste management
hierarchy, which favors waste prevention
and minimization and recycling, andevolution of waste management systems ineconomies as they develop.

10-15

Agricultural wastes,
residues andprocessing residues
from wood and agroindustry

Respecting the need to reserve some of theavailable resource for animal feed and toleave sufficient residues in the field for soil
protection, and consistent with other uses.

46-95

Wood harvesting
residues co-products

Used within the context of a sustainable
forestry plan, which takes carbon aspects
fully into account, along with measures tomaintain other forest characteristics
including biodiversity.

15-30

Agriculture

Produced on land in ways which do notthreaten food availability and whose use
leads to low land use change emissions,and subject to a positive assessment onother sustainability indicators such as
biodiversity and water availability andquality.

60-100

There is still a need for more work to improve the knowledge of the likely availability ofsuitable feedstocks for biofuels production and of their costs. Given the complex local
considerations that influence likely availability and costs, such assessments are best carriedout at national and regional level. Some examples of the results of such analysis areprovided below.
Information at national and regional levels
There have been a number of detailed studies on the availability and costs of the resourcesthat could be used as bioenergy feedstocks of the costs that can inform estimates of thelikely global situation. Some of these are summarized below.

7878

1EJ is equivalent to the energy contained in around 60 million tonnes of dry biomass feedstock.

58

Biomass availability and costs in USA
In the US, the national availability and cost of biomass have been assessed by US
Department of Energy (US DOE) in three studies known as Billion Ton Studies .79 According
to these studies, combined forestry resources, agricultural resources, wastes, and currently
used biomass total 1.2 billion tonnes under the base-case scenario (which assumes a 1%
annual increase in yield for agricultural and woody energy crop resources) and 1.5 billion
tonnes under a high-yield scenario (which assumes 3% annual increase in yield). Resources
available in the near term include agricultural residues, wastes, and forest resources. Energy
crops shown are scarce in the near term, but are the greatest source of potential biomass inthe future, contributing 411 million tonnes and 736 million tonnes in 2040 under the basecase and high-yield scenarios, respectively. This analysis indicates that most of the US
resource could be available “at the farm gate” or on the edge of a forest at a cost below 3
Eur/GJ, and delivered to users at costs between 3.3 and 5.6 EUR/GJ.
EU – S2Biom Study
The S2Biom project supports the sustainable delivery of non-food biomass feedstock at
local, regional and pan European level through developing strategies, and roadmaps,
informed by a computerized and easy to use toolset with updated harmonized datasets at
local, regional, national and pan European level for EU28, western Balkans, Turkey andUkraine.80 The study includes an estimate of the potential for biomass supply that could bemade available while respecting strict sustainability criteria by 2030.

79

Perlack, R. D., & Stokes, B. J. (2011). U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts

Industry. Oak Ridge National Laboratory. U.S. Department of Energy. Retrieved fromhttps://www1.eere.energy.gov/bioenergy/pdfs/billion_ton_update.pdf
Perlack, R. D., Wright, L. L., Turhollow, A. F., Graham, R. L., Stokes, B. J., & Erbach, D. C. (2005). Biomass as
Feedstock for a Bioenergy and Bioproducts Industry: The Technical Feasibility of a Billion-ton Annual Supply.
United States Department of Agriculture (USDA) and the United States Department of Energy (DOE). Oak
Ridge, Tennessee: Oak Ridge National Laboratory. Retrieved fromhttps://www1.eere.energy.gov/bioenergy/pdfs/final_billionton_vision_report2.pdf
US Department of Energy. (2016). 2016 Billion-Ton Report: Advancing Domestic Resources for a Thriving
Bioeconomy. US Department of Energy. Retrieved fromhttps://www.energy.gov/sites/prod/files/2016/12/f34/2016_billion_ton_report_12.2.16_0.pdf
80

FNR - Agency for renewable Resources. (2016, November). Welcome to the S2Biom project website.

Retrieved from S2Biom: www.s2biom.eu.

59Different types of agricultural residues that are currently underutilized could provide between
186 and 252 Million tonnes in the 2030-time frame with the lower estimates put strong
restrictions on collection of agricultural residues for reasons related to protection of soil
fertility, etc. Additional resources could be made available from sustainable forestry which
could provide between 615 million and 728 million tonnes by 2030. Wastes, includingorganic fractions of MSW could provide some 110-150 million tonnes per year in EU by 2030
(between 1.0 and 1.5 EJ).
A fourth major source of biomass relates to dedicated production of industrial crops on land
which is unused– either because of its poor quality or because it is agricultural land which
has been abandoned as a result of overexploitation, pollution, climate change and/or exodus
from rural areas. Estimates for the EU in 2030 are in the range of 84 million tonnes to 180
million tonnes of biomass while the respective figures for Western Balkans, Moldova andUkraine add another 54-62 Million tonnes.
The overall figures for all four categories are in the range of 1.0-1.4 billion tonnes of biomass
which could technically be available within Europe by 2030 under sustainable practices. The
study estimates the costs of the material at between 3 and 5 EUR/GJ at the roadside, similar
to the cost estimates in the US studies discussed above.
Amounts of feedstock in Brazil
Brazilian mills crushed 620 million tonnes of sugarcane during the 2018/2019 season. The
South-South-eastern region of the country were responsible for 70% of the crushed amount,
while the Centre-Western region accounted for another 22%81 (CONAB, 2019). The
processing of sugarcane stalks yields large amounts of bagasse (around 180 million tonnes
in 2018/2019, 50% moisture content), which are largely employed in integrated
Cogeneration of Heat and Power (CHP) units for the generation of both thermal andelectrical energy to supply internal process requirements. Sugarcane mills are able to export
part of the produced electrical energy to the national grid or sell a small portion of surplus
bagasse to the market. Besides sugarcane bagasse, sugarcane straw is also an abundantlignocellulosic material available for the bioenergy sector. Estimates point to an availability ofsome 43 million tonnes of sugarcane straw in Brazil (dry basis), considering a maximum
recovery of 50% of the straw in the field – the recovery rate should be limited to allow aminimum amount of straw to remain in the field to protect the soil.

81(CONAB, 2019).

60

Brazil has more than 7.5 million hectares of planted eucalyptus area. In 2017, 68 million m3
of eucalyptus were destined to the paper and pulp industry, 39 million m3 being used forenergy purposes, and another 26 million m3 employed for other purposes.82 The estimatedprice of this resource is in the range of 2.7 -3.7 EUR/GJ.

Conclusions
The theoretical availability and cost modelling indicate that large volumes of feedstock could
be made available for biofuels production, sufficient to meet likely future demand as
indicated in low carbon scenarios. Most of the material necessary could be supplied fromwastes and residues, and from sustainable forestry practices. Agriculture can also be an
important source of raw materials, with feedstocks produced in ways which complement
traditional agricultural production through co-cropping and through use of less productive
land.
Estimates of the potential available biomass and other uses vary significantly in theliterature. While the theoretical potential is high, the economic availability can vary greatly,
depending on numerous factors including yield and regional parameters (e.g. location andsize of crop/forest lands, local infrastructure, etc.). There is a wide range of biomass
availability globally, from as low as 95 EJ/year to as high as 350 EJ/year.
National studies indicate that much of the raw material could be produced and delivered tousers at costs of between 3 - 6 EUR/GJ. More information from real projects is needed totest the costs of procuring suitable feedstock in the real world.
National and regional assessments are very helpful in providing insights into likely long-term
availability and costs of feedstocks for bioenergy production, including for the production of
emerging biofuels. However, in order to be useful for estimating long term global availability
such assessments need to be done in a very transparent way, with clear classification of thevarious resources and of the assumptions made in defining how much material could inpractice be available, and around the sustainability considerations applied.
A useful step in harmonizing such approaches would be the development of some best82

Temer, M., Filho, S. J., Cruz, M., Filho, R. D., de Freitas, J. V., de Mesquita Junior, H. N., . . . de Oliveira, R. M.

(2017). Boletim Snif 2017. Serviço Florestal Brasileiro. 70818-900 - Brasília - DF, SCEN, Trecho 2, Bloco H:MINISTÉRIO DO MEIO AMBIENTE,. Retrieved fromhttp://www.florestal.gov.br/documentos/publicacoes/3230-boletim-snif-2017-ed1-final/file61practice guidelines for such studies, including some standardization and rationalization of theclassification of the various potential feedstocks, and of the sustainability constraints which
are applied. Such measures could facilitate the development of more consistent resource
estimates, which could be more easily compiled to give a global estimate, at least for key
producer and user regions.

62

GHG emissions of emerging biofuels pathways
Current legislation in the USA and the European Union require advanced biofuels to showat least 50% / 65% reduction in GHG emissions respectively, as compared to their fossil
fuel equivalents. The carbon intensity of a fuel is measured in gCO2e/MJ using Life Cycle
Assessment (LCA) and represents the GHG emissions emitted across the full life cycle ofa product system, from feedstock acquisition to production, use, and final disposition.
Carbon intensity of gasoline and diesel is about 95 gCO2e/MJ.
Emerging biofuels, termed advanced by either USA or EU legislation, do not automaticallyhave lower carbon intensity values than those of established biofuels. However, among
the various pathways that have been certified under California Low Carbon Fuel Standard(LCFS) program, the average carbon intensity values of advanced biofuels are typically,sometimes significantly, lower than those of established biofuels. The current average CI
values of biofuels (both established and emerging pathways) provided to California range
from 15 to 65 gCO2e/MJ, and can also be negative when obtaining credits for avoided
GHG emissions from waste disposal or if combined with CCS.
The location/region where the biofuel production facility is located will be a key
component of the final carbon intensity of the fuel. This is due to factors such as access to
low carbon intensity energy sources for heat and power, the potential to co-locate withother biofuel plants or oil refineries to develop efficient biofuel production and supply
chains, the type of biofuels and co-products produced, the type of feedstock andassociated logistics, land type used for crop/biomass cultivation and agronomic practices,
the local regulations on the use of feedstock, and carbon accounting mechanisms forbiomass.
As LCFS-type policies become more common in increasing numbers of jurisdictions, thecarbon intensity of current and emerging biofuels is expected to decrease.

Current GHG emissions of Renewable Transport Fuels
As discussed earlier, policies are increasingly incorporating sustainability criteria into biofuel
policy development. Life Cycle Assessment (LCA) of GHG emissions is currently the
predominant method used to assess the sustainability of many renewable fuel pathways,
including biofuel blending mandates. To become eligible, companies typically have to“petition” to be a supplier of a fuel via an approved fuel pathway. A fuel pathway is usually a63

combination of three components that include feedstock, production process, and fuel type,and an assessment of the fuels lifecycle GHG emissions will determine which fuel pathways
can qualify.
The EU’s RED II provides default GHG emission values and calculation rules for liquidbiofuels in Annex V and for solid and gaseous biomass for power and heat production in
Annex VI. The current default values will be revised and updated when technologicaldevelopments make it necessary. Producers have the option to either use default GHG
intensity values provided in RED II or to calculate actual values for their respective
production pathways83 with the REDII GHG savings thresholds for renewable fuelssummarized in Table 2.
Table 2: Greenhouse gas emissions savings thresholds in RED II 84
Plant operation start date

Transport
biofuels

Renewable transport fuels of
non-biological origin

Electricity, heating andcooling

Before October 2015

50%

-

-

After October 2015

60%

-

-

After January 2021

65%

70%

70%

After January 2026

65%

70%

80%

The US EPA’s RFS program covers the four categories of renewable fuels mandated under
this program and their minimum GHG reduction requirement is summarized in Table 3. A listof approved pathways for renewable fuels and completed pathway assessments under the
US EPA’s RFS program can also be found at https://www.epa.gov/renewable-fuel-standardprogram/approved-pathways-renewable-fuel.

83 Lonza, L. and O'Connell, A., 2018. Biofuels Production and Consumption in the European Union (EU): Status,
Advances and Challenges. IEA Bioenergy Task 39 Newsletter, December 2018.
http://task39.sites.olt.ubc.ca/files/2018/12/IEA-Bioenergy-Task-39-Newsletter-Issue-50-Final-Draft-1.pdf
84 Lonza, L. and O'Connell, A., 2018. Biofuels Production and Consumption in the European Union (EU): Status,
Advances and Challenges. IEA Bioenergy Task 39 Newsletter, December 2018.
http://task39.sites.olt.ubc.ca/files/2018/12/IEA-Bioenergy-Task-39-Newsletter-Issue-50-Final-Draft-1.pdf

64Table 3: Renewable fuel categories under the RFS program85,86 (US EPA, 2017a; Gottumukkala and Hayes,
2018)
Category

Code

Minimum GHG
emissions
reductionrequirment1

Description

Cellulosic Biofuel

D3

60%

Renewable fuels made from cellulose,
renewable gasoline, biogas-derived CNG and
LNG

Cellulosic Diesel

D7

60%

Cellulosic diesel, jet fuel and heating oil

Advanced Biofuels

D5

50%

Renewable fuels other than ethanol derived
from corn starch (sugar cane ethanol),biogas from other waste digesters, etc.

Biomass-Derived
DieselD4

50%

Renewable fuels that meet the definition ofeither biodiesel or non-ester renewablediesel.

Renewable Fuel

D6

20%

Renewable fuels produced from corn starchor any other qualifying renewable biomass

1 compared to the petroleum baseline

In contrast to biofuels blending mandates, LCFS policies do not have minimum GHG
emission reduction requirements for specific fuel categories. LCFS policies are fuel-agnostic,
with credits or deficits generated based on the carbon intensity (CI) of the particular fuel. The
carbon intensity of a fuel is estimated in gCO2e/MJ using LCA and represents the GHG
emissions emitted across the full life cycle of fuel from feedstock acquisition to production,use, and final disposition. Under LCFS policies, fuels that can be produced at a lower carbon
intensity compared to petroleum-based gasoline and diesel generate higher carbon credits.
This typically translates into higher market values for these fuels.
As summarized in Figure 8, the California LCFS program has described the carbon intensity
range of the major fuel pathways that have been certified in 2019. Each marker represents

85 US EPA, 2017a. Overview for Renewable Fuel Standard. Retrieved from https://www.epa.gov/renewablefuel-standard-program/overview-renewable-fuel-standard
86 Gottumukkala, L.D., and Hayes, D., 2018. Introduction to RINs. Retrieved fromhttps://www.celignis.com/RINs-credits.php

65the carbon intensity of an individual certified fuel pathway with the length of each bar
indicating the range that might be achieved by that particular pathway. The wide range ofcarbon intensities is due to several reasons such as the life cycle emissions methodology of
the LCFS, variations in feedstock types, origin of feedstock, raw material production
processing efficiencies and transportation distances and modes (e.g. rail vs. truck). All ofthese factors contribute to the carbon intensity of an individual producer’s fuel pathway. For
example, as indicated in Figure 9, the carbon intensity of ethanol could be as low as 7.18
gCO2e/MJ. For this pathway, ethanol is produced from California Energy Beets using biogas
derived from anaerobic digestion of green wastes and manure, with credit for avoided waste
management and co-products (compost and animal feed) contributing to the low carbon
intensity.

Figure 8: The carbon intensity values of current fuel pathways certified under the California LCFS program
Renewable Diesel is HVO/HEFA biofuels.

CARBOB shows the carbon intensity of conventional crude oil based on the average crude
oil supplied to California refineries and average California refinery efficiencies. Renewablegasoline is produced from co-processing of biocrude and crude oil in an oil refinery.
Hydrogen pathways include compressed and liquid H2 from central reforming of natural gas
and on-site reforming with renewable feedstocks. It is noted that the alternative fuel's carbon
66

intensity value is divided by its Energy Economy Ratio (EER) in order to obtain the EERadjusted CI value, representing the emissions that occur from the use of alternative fuel per
MJ of conventional fuel displaced87.
It is worth noting that emerging biofuels, such as cellulosic ethanol and drop-in hydrocarbons(e.g. renewable diesel, gasoline and Fischer-Tropsch Diesel), do not necessarily have lower
carbon intensity values than those of established biofuels (Figure 9). However, among thevarious pathways that have been certified under California LCFS program, the averagecarbon intensity values of advanced and drop-in hydrocarbons are typically, sometimes
significantly, lower than those of established biofuels. The lower carbon intensity of cellulosic
ethanol compared to corn ethanol is mostly due to the allocation of emissions associatedwith crop production, such as CO2 from nitrogen fertilizer production and N2O from nitrogen
fertilizer application, to the primary grain product. While there are diesel-related emissions
associated with crop residue collection and transportation, these are typically small
compared to the fertilizer (production and use) associated emissions allocated to grain.
However, there are exceptions, such as when an unsustainable volume of residue isremoved and additional fertilizer must be added to compensate for lost nutrients (Personalcommunications with (S&T) Squared Consultants Inc., 2018).

Figure 9: Minimum, average, and maximum carbon intensity (CI) values of some of the fuel pathways certified
under California LCFS program in 2019

87 California Air Resources Board, 2019b. LCFS Pathway Certified Carbon Intensities.
https://ww3.arb.ca.gov/fuels/lcfs/fuelpathways/pathwaytable.htm

67When the LCA values for the various oleochemical and lignocellulosic pathways toestablished and emerging drop-in hydrocarbons are summarized (Figure 10), a wide range
is apparent. This large variation, as demonstrated by algae derived HEFA, is due to a range
of issues such as a lack of maturity of the technology, differences in feedstock type, LCA
system boundaries, LCA model assumptions and data inventory and types of final
products/co-products.

Figure 10: Summary of LCA values derived from oleochemical and lignocellulosic pathways to produce
conventional and advanced drop-in hydrocarbons from various feedstock types88

88 Beavers, A.R., 2018. The potential of the aviation sector to reduce greenhouse gas emissions by using biojet
fuels. Master Thesis, The University of British Columbia.

68Future GHG emissions of Advanced Renewable Transport Fuels
As LCFS type policies become more common in increasing numbers of jurisdictions, thecarbon intensity of current and emerging biofuels is expected to decrease. Some of theapproaches used to decrease the GHG emissions of biofuels include:•

Development of “bolt-on” technologies which enable existing corn-ethanol dry mills in
the US to convert corn kernel fiber coproduct into cellulosic ethanol89,90.

•

Reusing or selling the carbon dioxide (CO2) produced by ethanol fermentation
instead of treating the CO2 co-product stream as a waste91.

•

Transitioning away from using fossil fuel-based energy sources such as coal andnatural gas to using heat and/or electricity from renewable sources such ashydroelectricity, biogas/renewable natural gas or agricultural and forest biomass inthe biofuels production processes•

For existing renewable diesel (HVO) facilities, using a green source of hydrogen can
reduce the carbon intensity of the resulting biofuels. For hydrogen-related emissions,renewable diesel facilities vary in the efficiency of hydrogen recovery from off-gasses
and re-use in the hydrotreating unit. Currently, existing renewable diesel facilities usehydrogen derived from methane-steam reforming. In general, hydrogen production
and utilization contributes 10-15 g CO2e/MJ to the carbon intensity of the final fuel
(Personal communications with (S&T) Squared Consultants Inc., 2018). Thus, use ofrenewable natural gas (RNG) or low carbon intensity electricity for hydrogenproduction will consequently lower the carbon intensity of renewable diesel.

•

One of the primary sources of GHG emissions of biofuels is those associated with

89 California Air Resources Board, 2017. California LCFS Tier 2 Fuel Pathway Application: Corn Kernel Fiber
Cellulosic Ethanol Pathway for Mid America Agri Products/Wheatland, LLC Using Natural Gas and Electricity as
Process Energy. GREET modeling technical support document.
https://ww3.arb.ca.gov/fuels/lcfs/fuelpathways/comments/tier2/t2n-1263_report.pdf.
90 California Air Resources Board, 2018. Lifecycle Emissions of POET Biorefining – Emmetsburg Corn Kernel
Fiber Cellulosic Ethanol with CA-GREET2.0
https://ww3.arb.ca.gov/fuels/lcfs/fuelpathways/comments/tier2/t2n-1266_report.pdf.
91 State CO2-EOR Deployment Work Group, 2017. Capturing and Utilizing CO2 from Ethanol: Adding Economic
Value and Jobs to Rural Economies and Communities While Reducing Emissions.
http://www.kgs.ku.edu/PRS/ICKan/2018/March/WhitePaper_EthanolCO2Capture_Dec2017_Final2.pdf

69

the upstream feedstock-related emissions92. As discussed earlier, the biomass
industry is making considerable progress in reducing the cost of biomass production
and logistics. These include cheaper crop establishment, harvesting, collection andtransportation by increasing the efficiency of logistics operations which result in a
reduction in energy consumption and the associated GHG emissions.
•

For fuel pathways that use Municipal Solid Waste (MSW) as feedstock, the carbon
intensity is impacted by the ratio of biological-to-non-biological content in the waste
and the ability of the biofuel plant to claim methane avoidance credits. As the
proportion of non-biological content in waste increases, so does the carbon intensityof the fuel. Methane avoidance credits are only possible if the baseline is landfilling
and there is no requirement for methane capture and use/destruction. This could
result in significant avoided landfill emission credit up to 300 g CO2e/MJ (Personalcommunications with (S&T) Squared Consultants Inc., 2018). The actual amount of
the emission credit depends on the local and municipal bylaws for methane capture
and use/destruction and the LCA method used in the LCFS to calculate the carbon
intensity value. Many landfills incorporate landfill gas collection systems and larger
landfills typically use this gas for electricity generation, while smaller landfills morecommonly employ gas flaring. In the case of the alternative being waste-to-energy
installations, the GHG credit of the electricity produced is a strong function of the
carbon intensity replaced grid power, the greener the grid the better becomes the fuelalternative. Considering that the greening of the grid is going fast in e.g. many EU
member states, this will favor the fuel use of MSW over waste-to-energy.

•

Forest residues that are currently burnt at the roadside of forest stands after logging
operations can be used for the production of biocrude, resulting in very low carbon
intensity values by avoiding emissions from slash pile burning. However, the actual
carbon intensity value depends on the treatment of forest feedstocks under carbon
accounting schemes, meaning that whether the forest biomass is considered as a
byproduct. For example, under current accounting approaches in Canada, harvest
residues are considered to be a by-product of the primary timber harvest. Avoiding
forest residues burning can more than offset emissions associated with collection,
preprocessing, and transportation, thereby resulting in a carbon negative feedstock.
Carbon accounting treatment of crop residues, including an assumed soil organic

92 O’Connell, A., Kousoulidou, M., Lonza, L., Weindorf, W., 2019. Considerations on GHG emissions and energybalances of promising aviation biofuel pathways. Renewable and Sustainable Energy Reviews, 101, 504-515.

70

carbon baseline, can also have a significant impact on final fuel carbon intensity(Personal communications with (S&T) Squared Consultants Inc., 2018).
It should be noted that the location/region where the biofuel production facility is located will
be a key component of the final carbon intensity of the fuel. This is due to factors such asaccess to low carbon intensity energy sources for heat and power, the potential to co-locatewith other biofuel plants or oil refineries to develop efficient biofuel production and supply
chains, the type of biofuels and co-products produced, the type of feedstock and associatedlogistics, land type used for crop/biomass cultivation and agronomic practices, the local
regulations on the use of feedstock, and carbon accounting mechanisms for biomass.
In summary, considerable progress has been made in both the production and use of
established and emerging biofuels. However, as well as on-going technical progress
lowering the cost and carbon intensity of the various biofuels, innovative policies will always
be required to bridge the price gap that can be anticipated as the world continues to wean
itself of non-sustainable fossil fuels.

71Role of policy on production and use of emerging biofuels
Policies have been and will continue to be essential if we are to foster the growth of
emerging biofuels used to decarbonize transport, particularly long-distance transport.
Policies used include blending mandates, excise tax reductions or exemptions, renewable
or low carbon fuel standards, as well as a variety of fiscal incentives and public financing
mechanisms. The countries that have achieved the most success in growing the
production and use of biofuels have used a mixture of market-pull and technology-pushpolicies.
To date, most of the policies used to promote transport decarbonization have focused onincreasing the use of biofuels in cars and trucks, at a national level. Other key transport
sectors such as aviation and shipping have drawn considerably less policy attention
despite being significant energy consumers and carbon/GHG emitters.
While the production and use of transport biofuels has more than doubled over the last
decade, progress in expanding biofuels production remains well below the levels required
to decarbonize transport significantly. Several factors continue to impact the effectivenessof biofuels policies such as relatively low petroleum and fossil fuel prices, uncertainty
about future policy and funding programs to support conventional and emerging biofuels,
the inconsistent regulation of global trade of biofuels and continuing concerns related tofood security, land use change and overall sustainability.

Current biofuel production volumes
Biofuels policies have and continue to support the growth of biofuels production and use.
The policies that have been successfully used to promote biofuels include blending
mandates, excise taxes exemptions/reduction and renewable or low carbon fuel standard(LCFS), fiscal incentives and public financing. These policies are applied at different stagesof the biofuel production and consumption chain and have helped enhance global biofuels
production from over 37 million tonnes oil equivalent (Mtoe) in 2007 (~64 billion liters) to over
84 Mtoe in 2017 (~145 billion liters)93. Although the reported increase of 3.5% from 2016 to

93 BP, 2018. BP Statistical Review of World Energy. 67th Edition.
https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review/bp-statsreview-2018-full-report.pdf

722017 was well below the annual growth rate of 11.4% achieved over the past decade, thiswas the most growth observed over a three-year period (Figure 11). Highest annual growthrate was observed in the Asia-Pacific region, where it grew at an annual rate of 20.1% from2006-2016 with a further 6% increase occurring from 2016 to 2017. The Americas andEurope continue to show the largest increase in biofuels production. In 2017, North America,
South and Central America and Europe had global biofuel production shares of 45.5%,
26.9% and 16.8%, respectively88.
The main biofuels produced were ethanol, biodiesel (fatty acid methyl ester or FAME fuels),
biofuels produced by treating animal and vegetable oils and fats with hydrogen (known ashydrotreated vegetable oil (HVO) or hydrotreated esters and fatty acids (HEFA) biofuels).
There was a concomitant increase in the contribution from biomethane in countries such as
the US, Sweden and Germany. As estimated, 65% of biofuel production (in energy terms)
was ethanol, 29% was FAME biodiesel and 6% was HVO/HEFA. The use of biomethane asa transport fuel, while growing rapidly, contributed less than 1% of the biofuel total94.

Figure 11: World biofuels production from 2007 to 2017. Biofuels production increased at an annual growth rateof 11.4%, from over 37 Mtoe in 2007 to over 84 Mtoe in 2017 (Adapted from BP, 2018)

94 REN21, 2018. Renewables 2018 global status report. http://www.ren21.net/gsr-2018/73

Although established biofuels (i.e., sugar/starch-based ethanol and FAME biodiesel)comprised more than 93% of global biofuels market share in 2017, worldwide efforts
continue to assess the potential production and use of drop-in hydrocarbons and emerging
biofuels. This is largely a response to the growth in policies requiring improved sustainability
attributes for the biofuels, especially lower life cycle net carbon emissions (lower carbon
intensity) and less potential to exacerbate undesirable land use change. For example, fuels
produced from agricultural, forestry, industrial or municipal wastes should typically show
improved LCA values as compared to current biofuels such a corn-derived-ethanol. In 2017,
the growth of biofuels was led by HVO/HEFA fuels, followed by ethanol from cellulosic
materials such as corn fiber, and by fuels from thermochemical gasification- or pyrolysisbased processes95. Over 3.1 Mtoe (4.4 billion liters) per year of HVO/HEFA biofuels are now
being produced globally89 (REN21, 2018). Waste and residue feedstocks now account for asignificant share of HVO/HEFA biofuels production, supporting deeper decarbonization fromthese fuels (REN21, 2018). Demand for HVO/HEFA biofuels is expected to continue to growbecause of their “drop-in” properties and low carbon intensities, particularly when produced
from “waste” oleochemical feedstocks such as tallow, used cooking and tall oils. Althoughthese fuels are primarily produced in Europe, Singapore and the US, production is expected
to grow as new facilities come on line and new investments are made to increase existing orbuild new plant capacities96.
The majority of HVO/HEFA biofuels are sold as renewable diesel, with a relatively small
portion of the oleochemical feedstock going to aviation biofuels (“biojet”) with most of thisfraction produced at AltAir’s facility in California97. Due to the higher production cost of HVO
as compared to FAME biodiesel, these fuels are mainly sold in markets such as California
and British Columbia where Low Carbon Fuel Standard policies incentivize biofuels based

95 IEA Bioenergy Task 39, 2019. Implementation Agendas - 2018 Update: A review of key biofuel producing
countries. http://task39.sites.olt.ubc.ca/files/2020/02/IEA-Bioenergy-Task-39-Implementation-Agendas-FinalDraft-Feb-4-2020.pdf

96

IEA Bioenergy Task 39, 2019. Implementation Agendas - 2018 Update: A review of key biofuel producing

countries. http://task39.sites.olt.ubc.ca/files/2020/02/IEA-Bioenergy-Task-39-Implementation-Agendas-FinalDraft-Feb-4-2020.pdf
97

van Dyk, S., Su, J., McMillan, J.D., Saddler, J., 2019. Potential synergies of drop‐in biofuel production withfurther co‐processing at oil refineries. Biofuels, Bioprod. Bioref., 13:760–775, DOI: 10.1002/bbb.1974.

74

on their carbon intensity, or where other supporting policies based on GHG emission
reductions such as in Germany and Sweden are in play (IEA Bioenergy Task 39, 2019).
While not yet commercialized, other routes to drop-in hydrocarbons that can leverage aportion of the substantial existing petrochemical/refining infrastructure are also underdevelopment. These include the development of non-renewable + renewable feedstock coprocessing approaches to help lower the carbon intensity of drop-in fuels that can be used inexisting vehicle engines (van Dyk et al., 2019).
The production of biofuels from cellulosic feedstocks, including cellulosic ethanol has, so far,only been demonstrated at a relatively small scale due to the slower than forecast progressin scale up and commercial deployment. Most cellulosic ethanol is now being produced in
the US primarily due to supporting policies. The 2019 volume requirements identified in the
US Renewable Fuel Standard (RFS2) for each of, advanced biofuels, cellulosic biofuels andbiomass-based biodiesel are 418, 4.92 and 2,100 million gallons, respectively98. In addition
to blending mandates for established biofuels, some EU member states, including Austria,
Denmark, Netherlands and Italy, have developed or are developing blending mandates foradvanced biofuels. As of 2021, these targets are supposed to become mandatory across theEU, based on the new provisions of RED II (IEA Bioenergy Task 39, 2019). The UK’s
recently implemented Renewable Transport Fuel Obligations Order (RTFO II) identifies
specific target for Development Fuels using incentives for certain types of biofuels, including
aviation and high blends, to try to facilitate their production and use.
Although only 38 million liters of US RFS2 eligible cellulosic ethanol was produced in 2018,the amount of so-called “generation one-point-five (1.5 Gen)” ethanol produced from cornkernel fiber in conventional corn ethanol plants is expanding. In 2017, five corn ethanol
plants, with a combined capacity of nearly 2 billion liters (500 million gallons), were approvedby the US Environmental Protection Agency (EPA) to generate Renewable Identification
Numbers (RINs99) credits under RFS2 program100. A number of pilot, demonstration and pre-98 US Environmental Protection Agency (US EPA), 2018. Renewable fuel standard program: standards for 2019and biomass based diesel volume for 2020. https://www.govinfo.gov/content/pkg/FR-2018-12-11/pdf/201826566.pdf
99 “Renewable Identification Numbers” (RINs) are saleable regulatory credits that represent a quantity ofqualifying renewable fuel. To qualify as a renewable fuel under the US RFS program, a fuel should be produced
from an approved feedstock through an approved pathway.
100 REN21, 2018. Renewables 2018 global status report. http://www.ren21.net/gsr-2018/75

commercial emerging biofuels plants in other countries such as Canada, Brazil, Austria,
China, India and Italy are also producing or have produced biofuels from biomass feedstocks
ranging from agricultural and forest residues and the cellulosic portion of municipal waste
streams. A list of current facilities that produce emerging biofuels at pilot and demonstration
scales can be found at the IEA Bioenergy Task 39’s large-scale demonstration plants
website: https://demoplants.best-research.eu. Details on demonstration facilities for various
pathways are provided in the sections “Emerging biofuel pathways”, “Low-carbon transport
fuels from fossil waste sources”, and “Low-carbon transport fuels from other forms ofrenewable energy” of this report.

Policies to increase biofuels production
Despite considerable progress being made in the technical aspects of emerging biofuels
production, it is widely recognized that the right policies will be needed to help expand
commercialization. For example, the Brazilian initiated Biofuture Platform, a 20-member
country collaboration, has highlighted the importance of the right policies enhancing lowcarbon biofuel production and use. EU policy support for emerging biofuels and theincreasing number of quota policies announced by member states is also anticipated tocatalyze commercial development. In other parts of the world, India plans to build twelve
cellulosic biofuel plants, several of which are in development, while China has indicated its
intent to develop cellulosic ethanol101.
Biofuel policies can be divided into technology-push and market-pull policies (Figure 12).
Typically, technology-push policies help drive early stage technology development such as
research, demonstration and commercialization of biofuels. These types of policies can beused to help reduce the cost of research and development, drive new ideas and take earlystage technologies through the valley of death that exists between initial development andcommercialization102. Other types of “financial investment” polices that have encouraged
expanded biofuels production and use include:•

Grants used to encourage conversion technology development, increase technology

101 BioFuture Platform, 2018. Creating the Biofuture: A report on the state of the low carbon bioeconomy.
http://biofutureplatform.org/wp-content/uploads/2018/11/Biofuture-Platform-Report-2018.pdf
102 Jordaana, S.M., Romo-Rabagob, E., McLearyb , R., Reidyb , L., Nazaric , J., Herremansb, I.M., 2017. The roleof energy technology innovation in reducing greenhouse gas emissions: A case study of Canada. Renewable
and Sustainable Energy Reviews, 78, 1397–1409.

76

readiness levels and de-risk the technology and associated supply chains. Related
programs have been used to de-risk early market development and to support
technologies with long-term market potential but high initial investment risk•

Loan guarantees to “buy-down” the risk of financing larger, first-of-a-kind commercial
facilities•

Corporate tax breaks to newly built biofuels production facilities•

Guaranteed return on renewable energy assets•

Compensation for depreciation of acquired renewable energy assets

Figure 12: Technology-push and market-pull biofuel policies. Countries that use a mixture of market-pull andtechnology-push policy instruments have been most successful at increasing biofuels production and use andalso at developing and deploying less mature emerging biofuels production technologies.

Market-pull policies, such as biofuels blending mandates and fuel/CO2 excise reduction/exemptions have proven effective in supporting technologies that are relatively mature,
helping create a demand for biofuels, as demonstrated by the established ethanol orbiodiesel markets103. However, these types of policies can sometimes be limited in theireffectiveness as some of these early-stage technologies can prove challenging tocommercialize, struggling to compete against fossil fuels and established biofuels. Marketpull policies such as California’s LCFS, the EU’s REDII, Brazil’s RenovaBio and Canada’s
Clean Fuel Standard (CFS) are examples of policies that hope to “pull” emerging biofuels
into the market by providing financial incentives to produce biofuels with the lowest carbon
intensity.
It is likely that effective technology-push and demand-pull policies will both be needed toincrease the rate of introduction and diffusion of emerging biofuel technologies. Although103

Costantini, V., Crespi, F., Martini, C., Pennacchio, L., 2015. Demand-pull and technology-push public support

for eco-innovation: The case of the biofuels sector. Research Policy, 44, 577-595.

77technology-push policies have been shown to generate innovation in emerging biofuels, thegrowth in demand induced by market-pull policies such as LCFS tends to increase public
and private investment in more mature technologies. The volume of low carbon fuelsconsumed in California increased from 2011 to 2017, from 1 152 million gasoline gallon
equivalent (GGE) in 2011 to 1 930 GGE in 2017, (a 60% increase) (Figure 13)104.

Fuel Volume (Millon GGE)

2 500
2 000
1 500
1 000

500
0
Ethanol

2011
2012
Biodiesel

2013
2014
Renewable Diesel

2015
2016
2017
2018
Fossil Natural Gas
Biomethane

2019
Electricity

Figure 13: Alternative low-carbon fuel volumes used in California 105

The influence of policies such as the LCFS can be seen in Figure 14 where the market valueof cellulosic ethanol in California increased from 3.74 in 2016 to 4.33 $/gallon in 2018, with
about 60% of the market value proving to be policy driven (RINs and LCFS premium). This
makes emerging biofuels with low carbon intensities cost-competitive with fossil fuels in the
California market. Thus, it is apparent that market-pull instruments will be critical for the
short-and-mid-term economic viability of the low carbon emerging biofuels. In addition,technology-push instruments such as R&D and grant instruments dedicated to emerging
biofuels will be required to drive early stage technologies towards demonstration andcommercialization.

104

California Air Resources Board, 2019. Data dashboard. Retrieved fromhttps://www.arb.ca.gov/fuels/lcfs/dashboard/dashboard.htm
105

California Air Resources Board, 2019. Data dashboard. Retrieved fromhttps://www.arb.ca.gov/fuels/lcfs/dashboard/dashboard.htm

78

5
4,5
0,51

4
3,5

0,8

3
2,5
2

LCFS Premium

2,3

RIN Credit

1,4Base Fuel Price (energy value)

1,5
1
0,5

1,54

1,52

2016

2018

0

Figure 14: The market value of cellulosic ethanol in California in 2016 and 2018106

Another example of the importance of policies is the package of clean energy and emissions
reduction goals passed by the European Commission under RED II. This includes a scaling
down of established biofuels and an increasing role for emerging biofuels and other lowcarbon alternatives, such as renewable electricity, to decarbonize transport. In Brazil, theRenovaBio program will introduce LCFS criteria to vehicular fuels, reinforcing the need forsustainability in biofuels production, consequently encouraging the production and use of
low-carbon emerging biofuels107.
Those policies have, so far, been primarily focused on road transport, especially at thenational level. Other transport sectors, such as rail, aviation and shipping, have, until
recently, received comparably less policy attention despite being large energy consumers
and GHG emitters. However, transport policies and industry efforts are increasingly focusedon decarbonizing long-haul transport sectors (i.e., road, rail, aviation and shipping), where
electrification is much more challenging. The aviation has adopted a number of targets,
including a 50% reduction in net aviation CO2 emissions by 2050 (compared to 2005
106 BiofuelDigest, 2018. The Digest’s 2018 Visual Guide to the economics, politics of renewable fuels.
Retrieved from http://www.biofuelsdigest.com/bdigest/2018/03/15/the-digests-2018-visual-guide-to-theeconomics-politics-of-renewable-fuels/
107 IEA Bioenergy Task 39, 2019. Implementation Agendas - 2018 Update: A review of key biofuel producing
countries. http://task39.sites.olt.ubc.ca/files/2020/02/IEA-Bioenergy-Task-39-Implementation-Agendas-FinalDraft-Feb-4-2020.pdf

79

levels)108 despite there being few direct support policies that target the use of renewablefuels in the aviation sector. Although Indonesia introduced a 2% renewable jet fuel mandate
in 2017, set to increase to 5% by 2025109, this has yet to be enforced. The EU’s new REDII
allows aviation and marine biofuels to “double-count” (using a multiplier of 1.2) in their
possible contribution towards the region’s renewable transport target110.
Shipping is another long-distance transport sector that is under increasing pressure to
reduce its carbon and sulfur emissions. Shipping mainly uses “heavy” fossil fuels that
contain sulphur and heavy metals and, in parallel with aviation, will likely prove to be one of
the hardest transport sectors to decarbonize. Apart from technological challenges, the typeof biofuels that will be used in shipping faces numerous barriers, such as the large price gap
between renewable and conventional fuels and very limited regulations, particularly
regarding the GHG emissions attributes of maritime fuels. International shipping is regulatedby the International Maritime Organisation (IMO). Since the Paris agreement (which did notinclude international shipping), the IMO has developed reduction strategies for GHG
emissions and other air pollutants. In 2016, the IMO agreed to a 0.5% cap on sulphur in its
fuels by 2020111. In 2018, the IMO reached an agreement on an “initial strategy” to reduce
CO2 emissions from shipping. The initial strategy identifies measures that could indirectly
support the GHG reduction efforts. One of these measures concerns the use of zero-carbon
or fossil-free fuels for the shipping sector and the development of robust lifecycle
GHG/carbon intensity guidelines for alternative fuels112.

108 International Air Transport Association (IATA), 2017. Climate Change: three target and four pillars.
https://www.iata.org/policy/environment/Pages/climate-change.aspx.
109 Widiyanto, S., 2017. Indonesian aviation biofuels and renewable energy initiatives. ICAO seminar on
alternative fuels. https://www.icao.int/Meetings/altfuels17/Documents/4%20Indonesia%20Initiative_Ministries.pdf
110 International Council on Clean Transportation (ICCT), 2018. Advanced Biofuel policies in select EU
members states: 2018 Update.
https://theicct.org/sites/default/files/publications/Advanced_biofuel_policy_eu_update_20181130.pdf
111 International Maritime Organisation (IMO), 2016. The 2020 global sulphur limit.
http://www.imo.org/en/MediaCentre/HotTopics/GHG/Documents/2020%20sulphur%20limit%20FAQ%20201
9.pdf
112

The Maritime Executive, 2018. IMO Agrees to CO2 Emissions Target. https://www.maritime-

executive.com/article/imo-agrees-to-co2-emissions-target

80Summary of the role of biofuels policies
In summary, policies have been and will continue to be essential if we are to foster thegrowth of emerging biofuels used to decarbonize transport, particularly long-distancetransport. Various types of policies have and will continue to be successfully used, including
blending mandates, excise tax reductions or exemptions, renewable or low carbon fuelstandard, as well as a variety of fiscal incentives and public financing mechanisms. These
policies have and will be applied at different stages of the biofuel supply chains (production
and consumption). To date, most of the policies used to promote transport decarbonization
have focused on increasing the use of biofuels in cars and trucks, at a national level. Other
key transport sectors such as aviation, shipping and rail have drawn considerably less policy
attention despite being significant energy consumers and carbon/GHG emitters.
The countries that have achieved the most success in growing the production and use of
biofuels have used a mixture of market-pull and technology-push policies. It is apparent thata balanced distribution of policy efforts between demand-pull and technology-push has been
most successful in fostering the development and deployment of biofuels technologies andthe growth of biofuels markets.
While the production and use of transport biofuels has more than doubled over the last
decade, progress in expanding biofuels production remains well below the levels required todecarbonize transport significantly. Policies are essential but have not been sufficient todrive the level of development that is needed. It is apparent that several factors continue toimpact the effectiveness of biofuels policies such as relatively low petroleum and fossil fuelprices, uncertainty about future policy and funding programs to support established andemerging biofuels, the inconsistent regulation of global trade of biofuels and continuing
concerns related to food security, land use change and overall sustainability.
Sustainability requirements are increasingly being incorporated into biofuels policies such as
LCFS-type policies that incentivize reductions in the carbon intensity and assure
sustainability. These types of policies should lead to more stable and increased markets,
promoting the greater production and use of emerging biofuels, particularly in sectors suchas aviation and marine, where appropriate biofuels can be readily integrated and used.

81

The likely costs of emerging biofuels production and the scope forcost reduction
The costs of producing emerging biofuels have been assessed in a recent IEA Bioenergy
study. The costs are currently significantly higher than the current costs of fossil fuelequivalents.
There is significant potential for reducing the costs of the assessed range of advanced
biofuels. In order to achieve these, projects must first demonstrate in practice that thecurrent production objectives in terms of reliable production at high availability andefficiency can be achieved consistently. The reductions will only then be achieved if there
are opportunities to build a significant number of further generations of plants which willallow experience to accumulate and provide the basis for learning, and for growing
confidence in the technologies.
Large scale deployment will depend on continuing policy support. First, industry will needsupport during the demonstration and risky and costly early commercialisation of thetechnologies, so as to bridge the “valley of death”. And then, continuing strong support will
be needed to offset the differences between biofuels and fossil fuel prices, and to
incentivise low carbon transport fuels.
While the costs of the advanced biofuels and other fuels discussed above are an
important factor, a broader range of issues also need to be considered when comparing
these options and also when looking at other low-carbon options. These include theextent to which they can directly replace fossil fuels, the costs of any modifications or of
distribution costs associated with fuels, the likely availability of feedstocks and the lifecycle GHG emissions associated with particular routes. The overall consideration of the
future for the advanced biofuels need to be seen in the context of these other factors, andbased on an analysis of full system costs, feedstock availability and life-cycle GHG
emissions.

Background
Bioenergy already plays an important role in the global energy economy and is a criticalelement in future low carbon scenarios, where it can especially play an important role in
reducing Green House Gas (GHG) emissions from the transport sector. Current biofuels
production is principally made up of ethanol and biodiesel (sometimes referred to as82

“conventional biofuels”). Future biofuel deployment will also require a range of bio-basedtransport fuels which are suitable for long-haul transport applications including aviation. A
number of appropriate technologies to produce such fuels are being developed andcommercialized, but so far, their production is only at a limited scale, although the productionof HVO has been growing rapidly and this growth is expected to continue with a production
capacity anticipated to grow from the current level of 5.5 billion liters/year to 13 billion liters
by 2024.113
In order to establish the current production costs of these fuels and the scope for these costs
to be reduced, a study has recently been completed as a project under the IEA Bioenergy
TCP.114 The principal results are summarized here.
This project used as its starting point a study on the costs of advanced biofuels carried out
within the program of work of the Sub-Group on Advanced Biofuels (SGAB) (under theEuropean Commission’s Sustainable Transport Forum (STF)) and published in 2017. The
report on this study reviewed data available on the current costs of producing a range ofadvanced biofuels, based on extensive contact with industry and other players active in thefield. The aims of this project were to:•Update and extend the SGAB study to provide estimates of the current costs ofproducing a selection of relevant novel advanced biofuels;•

Identify the scope for cost reduction for these advanced biofuels;•

Develop a model for likely cost reduction progress as deployment grows;•

Compare these costs and cost trajectories with likely trends in fossil fuel prices, andthose of established biofuels.

The project made direct contact with over 90 companies involved in developing a range ofadvanced biofuel technologies and used information they provided along with publishedstudies to assess current costs of production and the scope for cost reduction.

Current Production Costs
The study considered cost data on the following technologies, either using updated
information available from the companies contacted or from the literature, or else the data
provided in the SGAB report when this was found to be representative.

113

IEA Renewables 2019114

IEA Bioenergy, Task 43, Advanced Biofuels – Potential for Cost Reduction, ,https://www.ieabioenergy.com/publications/new-publication-advanced-biofuels-potential-for-cost-reduction/

83

Cost analysis confined to those technologies where estimates could be based at least in
substantial pilot plant work or on demonstration or commercial scale plant. The following
technologies were included:•

Production of hydrotreated vegetable oil (HVO) and methane produced by anaerobic
digestion (two options which are already widely deployed)•

Production of ethanol from cellulosic feedstocks by fermentation (including the
production of ethanol form corn fiber, integrated into a “conventional” corn ethanol
plant

•

Methane and methanol, produced by thermal gasification and synthesis, produced
from both biomass and waste-based feedstocks•

Fischer-Tropsch (FT) Liquids produced from biomass and waste feedstocks•

Fuels produced by pyrolysis followed by upgrading either in stand-alone plant or byco-processing with fossil fuels in an oil refinery. No significant cost difference wasfound between these two options.

Information gathered from industry and other sources was consolidated to provide a range of
cost estimates for each of the technology routes for which information was available. The
costs were broken down to show the contribution of capital, feedstock and operating costs.
The costs were normalized by assuming a standard financing rate with the capital charges
calculated using a finance cost of 10% and a project lifetime of 15 years. It was assumed
that plants could be operated for 8 000 hours per year. The costs were also scaled so as toconsider a large-scale plant size with a product output equivalent to 200MW.
Table 4 and Figure 15 summarize the results.

84

Table 4: Summary of current production cost ranges.

Costs, EUR/GJ
CapitalFeedstock
Costs

Operating
Costs

Total

Low

11.7

9.2

7.8

28.6

High

16.7

13.9

13.3

43.9

Low

9.2

0.0

5.0

14.2

High

10.6

0.0

5.8

16.4

Low

9.2

4.2

3.9

17.2

High

13.6

9.2

8.3

31.1

Low

11.9

-6.9

8.3

13.3

High

16.4

0.0

8.3

24.7

Low

11.9

5.0

3.9

20.8

High

20.6

13.9

5.6

40.0

Low

13.3

-6.9

8.3

14.7

High

20.6

0.0

8.3

28.9

Low

11.1

9.4

1.4

21.9

High

18.3

18.9

1.4

38.6

Low

10.6

4.2

8.1

22.8

High

10.6

8.3

16.4

35.3

Low

0.8

11.1

2.2

14.2

High

4.2

16.7

4.4

25.3

Low

6.9

-3.6

7.8

11.1

High

9.2

13.9

10.6

33.3

Process

Cellulosic ethanol

Cellulosic ethanol “1.5 Gen”

Methanol and methane- biomass

Methanol and methane - wastes

FT Liquids – Biomass

FT Liquids – Wastes

Bio-oil plus co- processing

Bio-oil stand alone

HVO

AD – Biomethane

Note: “Cellulosic ethanol”, 1.5 Generation most frequently refers to the production of cellulosic (suchas corn fiber) ethanol integrated into a corn-based ethanol plant.

85

50 Production cost EUR/GJ

40

30

20
Feedstock Costs
Operating Costs

10

Capital

Total
0

- 10

Low High Low High Low High Low High Low High Low High Low High Low High Low High Low High
Cellulosic Methanol and Methanol and FT Liquids – FT Liquids –Cellulosic
Bio-oil Bio-oil Biomass
Wastes coprocessing standaloneethanol ethanol “1 1/2 methanemethaneGen”
biomass
wastesHVO

AD

Figure 15: Summary of current cost ranges

The study largely confirmed the estimates of the current costs of producing advanced
biofuels contained in the earlier SGAB cost analysis report. Costs are in the range of 15
EUR/MWh to 44 EUR/GJ for production based on biomass feedstocks and 9 EUR/GJ to 26
EUR/GJ for waste-based production, illustrating the cost advantages of using such
feedstocks. The low cost of producing “1.5 generation ethanol” – ethanol produced form
cellulosic corn fiber in conjunction with conventional corn ethanol - illustrates the benefits ofintegrating “advanced” and conventional biofuels production.
These costs of advanced biofuels can be compared with those of conventional biofuels suchas starch/sugar-based ethanol and FAME-type biodiesel. US prices for both these fuels arereported by Iowa State University’s CARD program. The price of US ethanol is strongly
linked to corn prices, but over the last five years has been between 1.2 USD/gallon and 1.6
USD/gallon. This is equivalent to 13-15 EUR/GJ. Prices in Rotterdam and Brazil are
between 450-700 USD/m3 and 300-600 USD/m3 respectively (18-29 EUR/GJ and 12-24
EUR/GJ. According to the CARD program data, US biodiesel prices, strongly linked to soya
bean prices, have been between 2.8 USD/gallon and 3.5 USD/gallon, equivalent to 19-24
EUR/GJ. European biodiesel prices have been in the range of 19-28 EUR/GJ.
For comparison, the prices of the fossil fuel equivalents lie within a range of 8-14 Euro/GJ.

Potential for cost reduction
Many of the advanced biofuels technologies discussed here are still at relatively early stagesof deployment and commercialization, with only a handful of plants operating successfully at86

large commercial scale. There is therefore considerable scope for reducing costs. In thereport this is considered in two stages.
Where technologies are at an early stage of deployment, with only a few commercial plants
built and operating, there is significant potential for cost reduction as a few successor plants
are built, taking advantage of the experience gained in the first plants. The potential for such
reductions has been identified in discussion with project developers and are associated withimprovements due to continuing project optimization, improvement through on-going R&D
and in some cases by moving to larger scale plants to further benefit from scaling factors. In
addition as the technologies become better established, the technical risks will be seen as
less significant by project developers and financiers, and so capital for plants may become
available on more favorable terms, i.e. it should be possible to finance plants at lower
finance rates, as confidence in the technologies grow. Taken together these reductions arereferred to here as “medium term cost reductions” and could be realized within a 10-15-yeartime period if the necessary plants were built.
In addition there is further potential for “long-term cost reduction”, due to continuing learning
effects, such as have been experienced across a wide range of technologies and which areoften described using learning curves. A massive scale of deployment of these technologies
would be needed to reach the levels of contribution to global energy needs indicated in low
carbon scenarios such as the IEA 2DS scenario. Under these conditions significant
experiential learning could be expected. However, the extent of further cost reductions ismore difficult to estimate with any precision as they will depend on a wide range of factors. In
particular such reductions will depend heavily on the rate of deployment of the various
technologies. If attained, they would most likely be realized on a timescale beyond 15 years.
Medium term cost reduction
There is significant potential for cost reduction by process improvements through R&D andthrough experience being gained in the current generation of demonstration and earlycommercial plants. The industry players suggested that there was significant scope for cost
reductions to the capital and operating costs as a number of additional commercial plants
are built. For cellulosic ethanol processes it was considered that capital costs could be
reduced by between 25 and 50%, and operating costs by some 10-20%. For the range ofthermal processes, the reduction potential was judged to be lower, since these tend to be
based on unit operations which are well established in petrochemical and other applications.
Nonetheless it is anticipated that capital and operating costs could be reduced by between
10 and 20% in the medium term.
87Industry felt that the scope for feedstock cost reduction was more limited. While improved
efficiencies in supply chains might be possible in some cases, these might be offset by theneed to move to more expensive feedstocks, and by the fact that increased demand could
push up feedstock prices.
Further costs reductions could be achieved in the medium term if, once the technologies are
better established and thus perceived as less risky, finance could be made available on
more favorable terms. In modelling this impact it is assumed that finance can be madeavailable at a lower rate (8 instead of 10%) and over a longer period (20 rather than 15
years). This has the impact of reducing the capital element in the final production cost bysome 22%)
Table 5 and Figure 16 show the impact of such reductions on the costs of the range ofadvanced biofuels studied.
Table 5: Potential costs of biofuels production after reductions in EUR/GJ

Cellulosic

Methanol/

Methanol/ethanol/Methane/Methane

Biomass

Waste

FT
Liquids
Biomass

FT
Liquids
Waste

BiooilHVO

ADMethane

Lo

28,6

15,3

10,6

24,2

11,7

23,1

14,2

11,1

Hi

43,9

31,4

21,9

36,7

25,6

40,0

25,3

33,3

Lo

24,2

10,8

7,8

21,4

8,9

21,9

14,2

11,1

Hi

33,9

28,3

19,7

31,4

23,1

37,8

25,3

33,3

Lo

22,2

9,7

6,1

19,7

6,9

19,4

13,9

9,4

Hi

31,1

27,2

17,8

30,6

19,4

33,9

24,4

31,4

Current costs

With process
improvements

Lower cost ofcapital88

Figure 16: Potential costs of biofuels production after reductions

This indicates that these “medium term” reductions could lead to overall production costs
reduction by between 10-27%. In addition, if increased experience makes it possible tofinance plants on more favorable terms this will further reduce costs by some 5-16%. Taken
together these measures can reduce the production cost ranges from between 17 EUR/GJ
to 44 EUR/GJ to between 12 EUR/MWh and 33 EUR/GJ for production based on biomass
feedstocks, and from between 13-29 EUR/GJ to between 8 and 22 EUR/GJ for production
from waste feedstocks.
Long-term cost reduction
Achievement of the level of production of advanced biofuels envisaged within long term low
carbon scenarios will require extensive deployment of the technologies. For example,
producing the 25 EJ of advanced biofuels envisaged within the IEA’s 2DS Scenario would
require around 4 300 plants each producing the equivalent of 200 MW.115 Such large-scale

115

A biofuels plant with an output of 100 MW operating for 8000 h/year would produce fuel with an energy

content of 800 GWh, or 2.88 PJ. This is equivalent to:
108 thousand tonnes of ethanol (137 million litres or 36 million US Gallons)
144 thousand tonnes of methanol (183 million litres or 48 million US Gallons)65.5 thousand tonnes of HVO ( 84 million litres or 22 million US Gallons)89deployment will allow significant further opportunities for reduction in capital and operating
costs through experiential learning, as plant capital and operating costs fall in line with alearning curve, in which costs fall by a fixed proportion for each doubling of cumulative
production capacity. Such cost reductions have been seen across a wide range oftechnologies, including for conventional ethanol production where costs have fallen by some
20% for each doubling of cumulative capacity.
Such effects are likely to be seen also for advanced biofuel production, but such reduction is
likely to apply to the capital and operating elements of costs rather than to the feedstockelements. However, given the range of complicating factors it is difficult to estimate thescope for such reductions with any precision as this will depend on the learning rateachieved which may well differ between the technology options. To illustrate the potential
impacts of such reductions, Figure 17 illustrates the impact of a range of different learning
rates, assuming that feedstock costs remain constant.

100

Production cost EUR/MWh

80

60

40

20

0
10 x

100 x
Cellulosic ethanol

10 x

100 x

10 x

Methanol/Methane

20

100 x
FT Liquids

15

10

5

10 x

100 x

Biooil and processing

0

Learning rate %Figure 17: Examples of impact of learning in costs with increasing learning rates

As the figures show, depending on levels of deployment increase and of the learning rateachieved, experiential learning could have significant impacts on future costs, nearly 50% in
the most extreme case shown.

66 thousand tonnes of gasoline (90 million litres or 24 milion gallons)90

Importance of feedstock costs
Overall production costs are very sensitive to the feedstock costs and to the efficiency with which the energy inthe feedstock is converted into the final product, as indicated by

Figure 18.

Figure 18: Cost of feedstock in the overall cost of production

In the analysis of cost reduction potentials, it was assumed that feedstock costs remain
constant. Under these assumptions, as capital and operating costs fall, the feedstock costs
assume a greater importance in the overall cost structure.
It is difficult to predict feedstock cost and price trends particularly in situations where demand91

is significantly scaled up. While global and regional studies indicate that significant quantities
of wastes residues and energy crops could be available at roadside costs below 20
EUR/tonne (see section “Availability and costs of sustainable bioenergy feedstocks”), moredetailed studies are needed to confirm that feedstocks could practically be delivered at thesecosts taking all the logistical and market factors into account.

Benchmarking costs
The estimates of the current costs of production of the range of advanced biofuels have tobe benchmarked against the current prices of the fossil fuels that they aim to replace.
Analysis of recent oil price trends suggests that the costs of competing fossil fuels havebeen within the range of 8-14 EUR/GJ (allowing for the differences between the prices offinished petrochemical products and crude oil prices). This implies a significant cost gap of
between 3.3 EUR/GJ and 7.8EUR/GJ) between these prices and the estimates of thecurrent costs of advanced biofuels. If the medium-term cost reductions discussed above canbe achieved the gap will be narrowed but will still be significant (except for some wastebased projects). The cost reduction potential report estimates that the likely cost gap isequivalent to some 49-525 EUR/tonne of carbon dioxide equivalent (EUR/tCO2e) compared
to today’s costs and 0–365 EUR/tCO2e when cost reduction potential is factored incompared to recent fossil fuel price ranges
In the longer term, the effective cost of using fossil fuels may rise through a combination ofhigher prices and more extensive carbon pricing, or other incentives may be available for low
carbon transport fuels. If there is an extensive increase in the production capacity ofadvanced biofuels, then there is the prospect of the technologies being competitive in thecontext of anticipated fossil and carbon prices.

Conclusions
There is likely to be significant potential for reducing the costs of the assessed range ofadvanced biofuels. In order to achieve these, projects must first demonstrate in practice thatthe current production objectives in terms of reliable production at high availability andefficiency can be achieved consistently. The reductions will only then be achieved if there
are opportunities to build a significant number of further generations of plants which willallow experience to accumulate and provide the basis for learning, and for growing
confidence in the technologies.
Large scale deployment will depend on continuing policy support. First industry will needsupport during the demonstration and risky and costly early commercializationof thetechnologies, so as to bridge the “valley of death”. And then, continuing strong support will92

be needed to offset the differences between biofuels and fossil fuel prices, and to incentivize
low carbon transport fuels.
While the costs of the advanced biofuels and other fuels discussed above are an importantfactor, a broader range of issues also need to be considered when comparing these options
and also when looking at other low-carbon options. These include the extent to which they
can directly replace fossil fuels, the costs of any modifications or of distribution costs
associated with fuels, the likely availability of feedstocks and the life-cycle GHG emissions
associated with particular routes. The overall consideration of the future for the advanced
biofuels need to be seen in the context of these other factors, and based on an analysis offull system costs, feedstock availability and life-cycle GHG emissions.
There are some examples of policy and regulatory portfolios which have been introduced
and which are successfully leading to some early deployment and use of advanced biofuels.
The success of such policies should be monitored so that policy best practice can be applied
more widely. Some policy best practice examples are provided in Part 4 of our report (Howto reach widespread deployment of advanced renewable transport fuels).

93Compatibility of fuels with existing engines
The compatibility of fuels with fuel infrastructure and vehicles includes the aspects material
compatibility, tolerance, vehicle compatibility and vehicle compliance, i.e. fulfilment of all
regulatory requirements concerning pollutant emissions and safe vehicle use. Biofuels canbe used in low blends, as drop-in fuels with up to 100% substitution, or as special fuels in
dedicated or adapted engines.
The easiest way to introduce biocomponents is to operate within the framework of existing
standards for gasoline and diesel fuel. Typically, standards allow blending of ethanol and
FAME biodiesel corresponding up to an energy share 10-15%. Some activities to introduce
intermediate ethanol blends (E20, E25) are under way in Europe and are common practicein Brazil. However, for higher substitution and more substantial decarbonization of transport,
complementary actions are needed.
Drop-in type fuels are fully fungible with conventional hydrocarbon fuels and compatible withexisting vehicles and fuel infrastructure; no infrastructure or vehicle modifications areneeded. Paraffinic renewable diesel fuel, whether from hydrotreatment of oils and fats (HVO)
or Fischer Tropsch synthesis, can completely substitute fossil diesel and for mostperformance criteria is superior to regular diesel.
B100 is not a real drop-in type fuel, as it requires some changes in calibration, engine
hardware and maintenance schedules. Notwithstanding, some heavy-duty vehicle
manufacturers allow the use of B100 fuel in present-day sophisticated vehicles.
In the case of gasoline, there are no superior renewable hydrocarbon drop-in components,
as bio-gasoline hydrocarbon compounds tend to have low octane numbers. New blending
components, such as pure hydrocarbons, higher alcohols or ethers, could alleviate thechallenges.
Finally, special fuels can be used as such or as high blends in dedicated or adapted
engines. Such fuels are, e.g., gaseous fuels (methane, LPG), dimethyl ether (DME) and highconcentration alcohol fuels (E85, ED95). These fuels have a merit in chemically simple
structure, and in most cases, also inherently clean burning. However, the market introductionof such fuels has to go hand in hand with building up the refueling infrastructure and thevehicle fleet, requiring huge joint efforts.
The world population of natural gas vehicles exceeds 20 million units. Cleaned biogas,
biomethane, is a drop-in substitute for natural gas. Ethanol flex-fuel vehicles (FFV) are still
offered for the markets in North and South America, but have in practice vanished from the94European market. FFVs are a cost-effective way of enabling the use of high concentration
ethanol.
Regardless of the method to introduce biofuels, whether low-level blending, drop-in fuels or
special fuels for dedicated vehicles, fuel quality, vehicle/fuel compatibility and vehicle
compliance have to be maintained. Prerequisites are standards defining and securing fuelproperties and vehicles adapted to and certified for the fuels they are using. The fuel issimply not a parameter that can be decoupled from the rest of the system, which comprisesof engine, lubricant, exhaust after-treatment system, refueling infrastructure and regulation
regarding safety and emissions.

Introduction
For more than 100 years, internal combustion engines have mainly been operated onhydrocarbon fuels. Over the years, engines and fuels have been developed and improved inparallel. A modern road vehicle is a quite complicated and sophisticated piece of machinery.
To sustain performance and low exhaust emissions, fuel properties have to be kept withincertain boundaries. Some fuel parameters, such as octane number of gasoline and cetane
number of diesel fuel, are directly related to engine performance and integrity, whereassome other parameters, like sulphur and aromatic content, relate to exhaust emissions.
Prerequisites for using effective exhaust after-treatment systems are fuels with zero lead andultra-low levels of sulphur. A number of parameters are regulated to secure operation overtime (e.g., oxidation stability, residues, ash, corrosion). Some parameters relate to cold
weather operability (e.g., vapour pressure (gasoline) and cold-flow properties (diesel).
There are in principle three different ways to introduce biofuels for road vehicles:•

Low level blending of traditional biocomponents, e.g., ethanol, conventional biodiesel(fatty acid methyl ester FAME) within existing fuel standardsoSimple solution, but limited impact, typically only 10 – 15% energy
replacement•

Drop-in type components suitable for high level blendingoDrop-in fuel means a fuel that is fully fungible with conventional hydrocarbon
fuels and compatible with existing vehicles and fuel infrastructureoSimple solution, impact can be high, up to 100% replacementoParaffinic renewable diesel (Hydrotreated Vegetable Oil HVO, FischerTropsch diesel) is a kind of silver bullet for dieselo

No really good biocomponent options available for high level blending in
gasoline, bio-gasoline hydrocarbon (bio-naphtha) compounds tend to have95

low octane•

Dedicated fuels for dedicated vehiclesoGaseous fuels, high concentration alcohol fuelso”Chicken and egg” dilemma, what comes first, fuel infrastructure or vehicles?

The grouping above is suggestive, not absolute. Neat (100%) conventional FAME biodiesel
can be used in only slightly modified diesel engines, and in the case of dedicated vehicles,
biomethane (cleaned biogas) constitutes a drop-in alternative for natural gas.
Table 6 provides an overview of transport fuels and how they can be used in vehicles. Mostof these fuels can be produced via a number of pathways, i.e. from a range of feedstocks
and through various conversion technologies, see section “Technology pathways and status”
for details.

96

Table 6: Application of transport fuels
Fuel

Application in road transport
Gasoline blends (E5, E10, E85 in FFVs), stoichiometry and materials
issues constitute blending walls in conventional vehicles

Ethanol116

Additive treated ED 95 for diesel-type engines (commercial),
potentially also engines with assisted ignition (spark-plug, glowplug, dual-fuel)Low-level blends with gasoline

MethanolHeavy-duty engines as in the case of ethanol (additive treated fuel,engines with assisted ignition)

Various higher alcohols

E.g. butanol in gasoline blends

EthersE.g. MTBE (from methanol) and ETBE (from ethanol) in gasoline
blends, preferred by the auto manufacturers over ethanol ormethanol as such; blending wall stems from stoichiometry

FAME/Biodiesel

Drop-in hydrocarbons

Diesel blends (B7, B10, B20, B30), neat B100
Neat B100 typically requires some vehicle modifications
Gasoline-type components with limited octane for blending
components
Paraffinic HVO and Fischer-Tropsch diesel, drop-in, up to 100%
substitution
Passenger cars (mostly bi-fuel methane/gasoline vehicles)

MethaneHeavy duty vehicles with either mono-fuel or dual-fuel technology
On-board storage either as compressed biogas (CBG) for LD
vehicles or liquefied biogas (LBG) for HD vehicles
Application in shipping

Biofuels

Various types of bioliquids, including some “biocrudes” less stringent
fuel requirements than in the on-road sector

MethaneMainly dual-fuel engines, fuel storage in liquid form, currently fossil
natural gas, bio-methane could replace natural gas
Application in aviation

Liquid renewable fuels

116

Current regulation allows up to 50 % renewable components, very
stringent certification process, hydrotreatment (HEFA fuels),
synthesis and e-fuels potential routes to aviation fuels

Brazil: special case for ethanol, regular gasoline contains 27 % ethanol (E27), also hydrous ethanol (E100) on

the market, special vehicles flex-fuel/bi-fuel vehicles combing gasoline/ethanol with methane available

97

In markets with stringent vehicle and emission regulations, vehicles and fuels have to be onpair, meaning that a vehicle should be approved and certified for the fuel it is operating on.
Changing the fuel might have effects on the engine itself, the exhaust after-treatment systemand even the lubricant. One can thus state, that the fuel is not a parameter that can be freely
varied, it has to be a part of a balanced system (Figure 19).

Figure 19: Prerequisites for technical compatibility, and in the end, consumer acceptance.

Reasons for limiting the concentrations of certain components
The term “blending wall” used in conjunction with low-level blending of biocomponents into
commercial grade fuels means that for some technical reasons, there is a need to limit theconcentration of a certain component. This is done to safeguard operability and to makesure that commercial grade gasoline and diesel are compatible with the vehicle fleet and therefueling infrastructure in place. The need for limits can arise from chemical as well as fromphysical properties of biocomponents.
In the case of Europe, the Fuel Quality Directive 2009/30/EC (FQD)117, concerning thequality of gasoline, diesel and gas-oil, sets requirements for the parameters, which are mostcritical for engine performance and exhaust emissions. Some of the limits are directly linked
to the use of biocomponents.
For gasoline, there are limits for maximum oxygen content and maximum concentration ofindividual oxygenates. The oxygen content of the fuel affects the stoichiometry of the air-fuelmixture. In older or less sophisticated engines without closed-loop air-fuel ratio control,117

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increasing oxygen content means leaning out of the mixture, which eventually can lead to,e.g., misfiring, overheating and engine malfunction. Modern gasoline cars with closed-loop
lambda control can, to a certain degree, compensate for fuel oxygen.
There is also a need to limit the concentration of oxygenates from a materials compatibility
point of view. Ethanol is corrosive, polar and conductive, and can attack metals andelastomers. Methanol is even more challenging than ethanol in this respect. Higher alcohols
and ethers, on the other hand, are less prone to cause problems.
The limits on oxygenated compounds set by the FQD are:•oxygen content maximum 3.7% m/m (corresponds to 10% v/v ethanol)•

ethanol content maximum 10% v/v (E10)•methanol content maximum 3% v/v•

higher alcohols and ethers maximum 12…22% v/v, depending on the component

There is also a maximum limit on the vapor pressure of summer grade gasoline, 60 kPa. At
low concentrations, ethanol tends to increase the vapor pressure of gasoline (azeotrope
formation). Thus the volatility of the base gasoline might need adjusting when blending in
ethanol. Excessive vapor pressure might lead to elevated evaporative emissions as well as
to malfunctions due to vapor lock in the fuel system.
In the case of diesel fuel, the FQD limits the content of conventional FAME-type biodiesel to
7% v/v (B7), with some exceptions for fleet operations. There are several reasons for this(see also Worldwide Fuel Charter later in the text):•

some materials issues with elastomerso•FAME is a strong solvent

high end of distillation temperature for FAMEocould lead to engine oil dilution•

limited oxidation stability•

limited cold flow properties•

certain impurities carried over from feedstock and process

The background information in the FQD states:“In order to facilitate the effective marketing of biofuels, CEN (European Committee forStandardization) is encouraged to continue working rapidly on a standard allowing theblending of higher levels of biofuel components into diesel and, in particular, to develop astandard for ‘B10’.
A limit for the fatty acid methyl ester (FAME) content of diesel is required for technical99

reasons. However, such a limit is not required for other biofuel components, such as purediesel-like hydrocarbons made from biomass using the Fischer-Tropsch process or hydrotreated vegetable oil.”

Definitions for compatibility
There are different levels of compatibility, starting from materials compatibility to thecompliance of the vehicle and the fuel to be used. ACEA, the European Automobile
Manufacturers' Association, has defined compatibility and compliance in the following
way118:•Material compatibility: the fact that the material withstands exposure to the fuel (type)
without negative effects concerning the durability and performance of the exposedmaterial if the fuel (type) would be used.

•

Tolerance: compatibility based on lifetime running on the fuel (type) withoutcompromising vehicle safety or performance issues when using the fuel (type).

•

Vehicle compatibility: guarantee that the vehicle is declared to be tolerant for the useof the fuel (type) and fulfils vehicle manufacturer defined conditions in respect ofcustomer expectations for day-to-day vehicle operation.

•

Compliance of a vehicle: when using the fuel (type) the vehicle fulfils all regulatory
requirements concerning pollutant emissions and safe vehicle use assessed on thebasis of tests using regulated reference fuels for the fuel (type).

As stated in the last bullet, reference or certification fuels are needed for the emission
certification of vehicles. These fuels can be special certification fuels (reflecting market
quality) or fuels fulfilling a certain standard. On the international level, special certification
fuels are defined by UNECE WP.29, Regulation 83119. Fuels included are E5, E10, E85, E75(“winter quality E85”), B5, B7, and in addition, certain gaseous fuels.
For the U.S., the Environmental Protection Agency (EPA) defines emission certification
fuels120.
The European Union in principle falls back on UNECE. Specifications for certification fuels

118

https://www.nen.nl/Evenementen/Presentaties/20190625-Presentaties-Future-

fuels.htm?utm_medium=email (Andreas Kolbeck)119

https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:42015X0703(01)&from=EN

120

https://www.epa.gov/emission-standards-reference-guide/epa-emission-standards-light-duty-vehicles-and-trucks100

are included in the emission regulations121. In some cases, a reference is made to European
fuel standards (actual EN standards, draft standards or even so-called workshop
agreements). The Euro VI regulation for heavy-duty engines requires heavy-duty engines tobe certified on the fuel they will be running on122. Possible alternatives are, e.g., B7, B10,
B20/B30, B100, 100% paraffinic diesel (XTL), gaseous fuels and also ED95 (additive-treatedethanol for diesel engines).

Legislation, standards and recommended practices
Fuel quality and fuel composition are regulated on various levels, both internationally andnationally.
The highest level, legally binding, is defined by laws, Directives (EU) and regulations.
In the case of Europe, e.g., the Fuels Quality Directive 2009/30/EC and regulation
concerning vehicle emissions are legally binding. Likewise, in the U.S., the US Codes ofFederal Regulations are binding. As said, the FQD regulates the fuel parameters, which aremost critical for engine performance and exhaust emissions.
The second level is standards. Standards are, in principle, voluntary agreements and notlegally binding, representing industry practice. A standard is based on consensus among allinterested parties123. There are international, regional and national fuel standards, e.g., ISO(International Organization for Standardization), CEN (European Committee forStandardization) and ASTM (American Society for Testing and Materials) standards. Some
EN and ASTM standards are also recognised internationally (e.g., aviation fuels are certified
by ASTM124). In some cases national legislation can refer to standards, thus making
standards legally binding.
Standards are typically more comprehensive than the legally binding documents. The
European FQD only lists 6 parameters for diesel fuel, whereas the European standard fordiesel fuel, EN 590125, all in all list 16 parameters to be controlled. The additional

121

https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32017R1151&from=EN122

https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=celex:32018R0932

123

https://www.nen.nl/Evenementen/Presentaties/20190625-Presentaties-Future-

fuels.htm?utm_medium=email (Ortwin Costenoble: standards)
124

https://www.astm.org/cms/drupal-7.51/newsroom/astm-aviation-fuel-standard-now-specifies-bioderived-

components
125

EN 590:2013+A1:2017 (WI=00019524) Automotive fuels - Diesel - Requirements and test methods

101parameters relate to functionality and vehicle durability, e.g., lubricity, corrosion, ash,sediments, oxidation stability and cold operability.
For oxygen and ethanol content of gasoline and FAME content of diesel, the EN standards
are in congruence with the FQD. The European standard for diesel fuel contains both aminimum and a maximum value for density (FQD only has a maximum density value). In EN
590, minimum density is 820 kg/m3 for summer grade fuel and 800 kg/m3 for winter grade
fuel. Especially the minimum value of summer grade diesel, 820 kg/m3, limits the share ofparaffinic renewable diesel (HVO, BTL) that can be blended into commercial grade EN 590.
Paraffinic diesel is typically lighter than regular diesel, with a density of some 780 kg/m3.
Figure 20 presents an overview of the European fuel standards currently in place. Not all ofthese standards are necessarily for use as motor fuels or as such (e.g. EN 16900 specifies
fast pyrolysis bio-oils for boiler use at industrial scale, EN 15376 ethanol used as a blending
component).

Figure 20: Current European fuel standards7.

Conventional diesel (EN 590) may contain up to 7% v/v FAME. There are also standards for
B10126 (can be marketed to the general public), B20/B30127 (for use in captive fleets only)

126 EN 16734:2016+A1:2018 (WI=00019543) Automotive fuels - Automotive B10 diesel fuel - Requirements
and test methods
127 EN 16709:2015+A1:2018 (WI=00019549) Automotive fuels - High FAME diesel fuel (B20 and B30) -102

and B100128 (FAME as a blending component or for use in engines adapted to this fuel).
As of 2016, there is a standard for paraffinic diesel. EN 15940129. This standard covers
diesel fuel from synthesis or hydrotreatment, which means BTL, GTL (gas-to-liquids) andHVO fuels. EN 15940 states:“Paraffinic diesel fuel does not meet the current diesel fuel specification, EN 590. The maindifferences between paraffinic diesel fuel and automotive diesel fuel are in the areas ofdensity, sulfur, aromatics and cetane. Its density can be outside the regular diesel
specification, and the described class A type fuel has a higher cetane number. Paraffinic
diesel fuel is not validated for all vehicles, consult vehicle manufacturer before use.
Paraffinic diesel is a high quality, clean burning fuel with virtually no sulfur and aromatics.
Paraffinic diesel fuel can be used in diesel engines also to reduce regulated emissions.”
The standard for gasoline, EN 288130, covers two gasoline grades, E5 (maximum 5% v/v
ethanol and 1.85% m/m oxygen) applicable to all gasoline engines, and E10 (maximum 10%v/v ethanol and 3.7% m/m oxygen) for those vehicles which are E10 compatible.
There is also a standard for high concentration ethanol fuel, E85131, to be used in flex-fuelvehicles. The standard for anhydrous ethanol E100132 is applicable for ethanol used as a
blending component.
As indicated in Figure 20, the European Commission has initiated a process to increase theallowable ethanol concentration of gasoline. As a part of this process, in 2015 - 2019, a
research project “Engine tests with new types of biofuels and development of biofuel
standards” was carried out by CEN with Netherlands’ Standardization Institute (NEN) as

Requirements and test methods
128 EN 14214:2012+A2:2019 (WI=00019562) Liquid petroleum products - Fatty acid methyl esters (FAME) for
use in diesel engines and heating applications - Requirements and test methods
129 EN 15940:2016+A1:2018+AC:2019 (WI=00019563) Automotive fuels - Paraffinic diesel fuel from synthesisor hydrotreatment - Requirements and test methods
130 EN 228:2012+A1:2017 (WI=00019523) Automotive fuels - Unleaded petrol - Requirements and test
methods
131 EN 15293:2018 (WI=00019511) Automotive fuels - Automotive ethanol (E85) fuel - Requirements and test
methods
132 EN 15376:2014 (WI=00019452) Automotive fuels - Ethanol as a blending component for petrol Requirements and test methods

103

coordinator133. Regarding standardization, the main conclusions were:•

E20 should be feasible as a fuel in Europe, as most post-2011 vehicles in fact arecompatible with E20•

tests methods for FAME should be improved to safeguard the robustness of FAME
blended fuels•

The lower density limit of summer grade EN 590 diesel fuel could be lowered to 800
kg/m3, to allow blending in of increased amounts of paraffinic components (meaning
up to 50% paraffinic renewable diesel in EN 590)

The fuels in use vary by region and country. In the U.S., the fuel grades include E10, E15,
E85, B5 and B20134. ASTM D4814 135 defines gasoline fuels with up to 15% ethanol. The
use of E15 is approved for use in model year 2001 and newer light-duty conventional gas
vehicles. ASTM D 6751136 specifies biodiesel (B100) for use as a blend component withmiddle distillate fuels, whereas ASTM D7467137 specifies the blended fuels (B6…B20).
In Brazil, all gasoline contains 27% ethanol (E27). In addition, neat ethanol (E100) is on themarket. For diesel fuels, there is a blending mandate that will reach 15% FAME (B15) in
2023, and currently this value is 12%138.
The third level is ”Code of Practice” type documents and recommendations. This group
includes documents such as:•

Worldwide Fuel Charter (WWFC)139 of the auto and engine manufacturersoencompasses fuel quality recommendations by region and by degree ofsophistication of emission regulations•

133

CEN guidelines for good housekeeping (diesel fuel140, gasoline141, prevention of

https://www.nen.nl/Evenementen/Presentaties/20190625-Presentaties-Future-

fuels.htm?utm_medium=email (Ortwin Costenoble: H2020 project)134

https://afdc.energy.gov/

135

https://www.astm.org/Standards/D4814.htm

136

https://www.astm.org/Standards/D6751.htm

137

https://www.astm.org/Standards/D7467.htm

138

https://www.iea-

amf.org/app/webroot/files/file/Workshop_Transport_Decarbonisation/02%20Brazilian%20Perspective%20on%20Transport%20Decarbonisation%20-%20Miguel%20Oliveira.pdf (fuel specs mentioned orally)139

https://www.acea.be/uploads/publications/WWFC_19_gasoline_diesel.pdf

104cross contamination142)•

CONCAWE guidelines for handling and blending FAME143

The sixth and most recent edition of the Worldwide Fuel Charter was published in October
2019. It defines 5 categories or specifications for gasoline (2 - 6, category 1 is abolished as
obsolete) as well as for diesel (1 - 5). Category 6 (for gasoline) and category 5 (diesel) are
fuels fit for markets with the most stringent emission regulations. In fact, category 6 forgasoline is forward-looking, anticipating increased efficiency requirements and defining
octane levels of 98 and 102 RON.
The Worldwide Fuel Charter is published by the members of the Worldwide Fuel Charter
Committee as a service to legislators, fuel users, producers and other interested parties
around the world to provide advice on sufficiency and fitness for purpose. The document
states:“The Charter and Guidelines have two purposes: to inform policymakers and other interested
parties how fuel quality can significantly affect engine and vehicle operation, durability andemissions performance throughout the year; and to promote harmonized fuel quality
worldwide in accordance with vehicle, engine and emission control system needs, for the
benefit of consumers and the general environment. The Charters impose no obligation on
any users or producers of fuel, and they do not prohibit use of any engine or vehicle
technology or design, fuel, or fuel quality specification. They are not intended to, and do not,replace engine and vehicle manufacturers’ fueling recommendations for their engine andvehicle products. Consumers are encouraged to check their vehicle owner manuals for
specific guidance and to compare that guidance with fuel dispenser labels.”
In addition to the five specifications for gasoline and five specifications for diesel, the WWFC
presents plentiful of technical background information. The chapter on gasoline also
discusses oxygenates. As for oxygen content and concentration of individual oxygenates,
the WWFC falls back on the FQD and EN 228 (e.g., oxygen 3.7% m/m, ethanol 10% v/v,
methanol 3% v/v). However, there is a provision for increased amounts of oxygenates:

140

https://infostore.saiglobal.com/en-us/Standards/CEN-TR-15367-1-2014-334308_SAIG_CEN_CEN_767928/

141

https://infostore.saiglobal.com/en-us/Standards/CEN-TR-15367-2-2007-334309_SAIG_CEN_CEN_767930/

142

https://infostore.saiglobal.com/en-us/Standards/CEN-TR-15367-3-2009-334310_SAIG_CEN_CEN_767932/

143

https://www.concawe.eu/publication/report-no-909/ https://www.concawe.eu/publication/report-no-

308/

105

“To achieve 98 - 102 RON, the Charter provides flexibility for oxygen to reach up to 8% m/m(equivalent to about 20 - 22% v/v ethanol), but only for vehicles designed for such fuel andwhere dispensers are labelled to enable consumers to determine if their vehicles can use aparticular gasoline-ethanol blend.”
For methanol, the WWFC states:“The use of methanol is only acceptable if: (i) specified by applicable standards (e.g.,
maximum 3% v/v methanol in standard EN 228); (ii) consumed in vehicles compatible with
its use; and (iii) stated in the owner's manual.”
The chapter on diesel includes a part discussing biofuels and alternative synthetic fuelcomponents. Regarding conventional biodiesel, the WWFC presents a long list of possible
problems:•

Biodiesel may be less stable than conventional diesel fuel, so precautions areneeded to avoid problems linked to the presence of oxidation products in the fuel.
Some fuel injection equipment data suggest such problems may be exacerbatedwhen biodiesel is blended with ultra-low sulphur diesel fuels.

•

Biodiesel requires special care at low temperatures to avoid an excessive rise inviscosity and loss of fluidity. Additives may be required to alleviate these problems.

•

Being hygroscopic, biodiesel fuels require special handling to prevent high watercontent and the consequent risk of corrosion and microbial growth.

•

Deposit formation in the fuel injection system may be higher with biodiesel blends
than with conventional diesel fuel, so deposit control additive treatments are advised.

•

At low ambient temperatures, FAME may produce precipitated solids above the cloud
point, which can cause filterability problems.

•

Biodiesel may negatively impact natural and nitrile rubber seals in fuel systems. Also,
metals such as brass, bronze, copper, lead and zinc may oxidize from contact withbiodiesel, thereby creating sediments. Transitioning from conventional diesel fuel tobiodiesel blends may significantly increase tank sediments due to biodiesel’s higher
polarity, and these sediments may plug fuel filters. Thus, fuel system parts must be
specially chosen for their compatibility with biodiesel.

•

Neat (100%) biodiesel fuel and high concentration biodiesel blends havedemonstrated an increase in nitrogen oxide (NOx) exhaust emission levels.

•

Biodiesel fuel that comes into contact with the vehicle’s shell may be able to dissolve
the paint coatings used to protect external surfaces.

Consequently, the WWFC is rather restrictive towards FAME. For categories 1 - 4, maximum106

FAME content is 5% v/v. In category 5, no FAME is allowed (non-detectable). Throughout all
five categories of diesel fuel, there are comments on “other biofuels” and “ethanol/methanol”:•

Other biofuels include HVO and BTL. Blending level must allow the finished fuel tomeet all the required specificationso•this is basically in congruence with the FQD (authors’ comment)

Ethanol/methanol must be at or below detection limit of the test method used

Fuel quality marking for Europe
As of October 2018, in order to avoid confusion for consumers and businesses, a newcompulsory fuel labelling system for Europe has been introduced. The system covers all 28
European Union member states, the EEA countries (Iceland, Lichtenstein and Norway), theformer Yugoslav Republic of Macedonia, Serbia and Turkey. The system is based on acommon and harmonized set of fuel labels for use on newly produced vehicles as well as at
all filling stations dispensing gasoline, diesel, hydrogen, compressed natural gas, liquefied
natural gas or liquefied petroleum gas fuels, as well as at vehicle dealerships144.
These labels are placed on the nozzles of all filling pumps, on the pumps themselves and in
the immediate proximity of the fuel filler flap/cap of newly produced passenger cars, mopeds,
motorcycles, tricycles and quadricycles, light commercial vehicles, heavy-duty commercial
vehicles and buses and coaches. They should also appear in the vehicle owner's manual,and they may appear in the electronic handbook available via a vehicle's infotainment
center.
The system stems from Directive 2014/94/EU145 on deployment of alternative fuelinfrastructure. The system guarantees compatibility, but not necessarily bio content, eventhough the labels refer to biocomponent concentrations. Gasoline-type fuels are marked witha circle, diesel-type fuels with a square and gaseous fuels with a diamond (Figure 21).

144

https://ec.europa.eu/commission/presscorner/detail/en/MEMO_18_6102

145

https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32014L0094&from=en

107

Figure 21: The new fuel labelling system for Europe28.

Figure 22 (diesel truck fuel tank and fuel dispenser) shows actual photos of the markings. In
this case, the truck is approved for B7, B10 and 100% paraffinic diesel fuel (XTL). The
dispenser, on the other hand, provides two grades of gasoline (E5 and E10), and two gradesof diesel (B7 corresponding to EN 590) and 100% renewable HVO diesel (XTL,
corresponding to EN 15940)

108

Figure 22: Actual photos of fuel markings (truck fuel tank and fuel dispenser).

Examples of vehicle adaptation to special fuels
As stated earlier, it is possible to use special fuels, namely some high concentration liquidbiofuels and gaseous fuels, in dedicated or adapted engines. In most cases, 100% paraffinic
renewable diesel does not require any engine modifications, and even B100 requires only
minor modifications to engine hardware and maintenance procedures.
It is, in principle, relatively simple to modify a gasoline car to run on high concentration
ethanol E85. E85 consists of up to 85% v/v ethanol, the balance being hydrocarbons tofacilitate cold starting. However, when an OEM vehicle manufacturer makes a so-called flex
fuel vehicle (FFV), capable of running on any fuel from neat gasoline to E85, several
considerations have to be made, e.g.;•materials compatibility of the fuel system as well as of the base engine itself•

proper calibration of the fuel system including adaptation to the fuel in use•

securing adequate emission performance, including operation at low ambient
temperatures•

coping with potential safety issues arising from, e.g., the evaporative behavior andconductivity of ethanol

Figure 23 shows features of flex fuel vehicles.
It is self-evident, that simple aftermarket conversions to E85, focusing merely on therecalibration of the fuel system, cannot deliver adequate performance and safety, and should109therefore not be recommended. E.g. ACEA speaks strongly against aftermarket
conversions146.
FFVs have almost disappeared from the European market. There are at least two reasonsfor this. Firstly, the Euro 6 emission regulation requires emission certification with E85 also
at -7 oC, which poses some calibration challenges. Secondly, there is no real incentive forthe auto manufacturers to produce FFVs, contrary to zero carbon dioxide (CO2) tailpipe
electric vehicles. However, in the Americas, North and South, there is still an ample offeringof FFVs.

Figure 23: Flex fuel vehicle features147.

There are a number of heavy-duty engines approved for B100 fuel. The Association
Quality Management Biodiesel (AGQM) was founded in 1999 as an initiative for the quality
assurance of leading biodiesel producers and traders. AGQM maintains a list of approvals

146

https://www.acea.be/publications/article/position-paper-aftermarket-flexfuel-converters

147

https://afdc.energy.gov/vehicles/flexible_fuel.html

110for B20/B30 and B100 fuels148. Included on the list of manufacturers that allow the use ofB100 in certain latest technology Euro VI engines are companies such as DAF, Daimler(Mercedes-Benz), MAN, Scania and Volvo. AGQM’s web page also contains links to fuelrelated technical bulletins of the manufacturers. The bulletins typically contain someprovisions and comments regarding the use of B100, e.g.:•

the fuel has to fulfil the EN 141214 standardoin some cases additional requirements on ash and phosphorus to safeguard
particulate filters against blockingo•reduced service intervals of particulate filters (ash removal)

engines have to be ordered with special calibration and some special components for
B100 operation•

increased urea consumption in the selective catalytic reduction (SCR) system due tohigher engine-out NOx emission•

reduced engine output and increased volumetric fuel consumption due to lower
volumetric heat value in comparison with regular diesel•

reduced engine oil, oil filter and fuel filter exchange intervals for B100•

higher engine oil viscosity to compensate for engine oil fuel dilution

Effects of biofuels on tailpipe emissions
Currently, the main motivation for implementation of biofuels is reduction of CO 2 emissions.
However, to some extent biofuels can also contribute to the reduction of harmful tailpipe
emissions.
When estimating the impact of biofuels on air pollutant emissions from road vehicles, there
are two determining factors to consider: first, the combination of the vehicle’s engine andexhaust after-treatment technology; and second, the characteristics of the biofuel comparedwith the fossil fuel being replaced. Taken together, these two components provide anindication of the performance of biofuels relative to fossil fuels in terms of air pollutant
emissions and impact on human health.
With sophisticated engines and after-treatment technology, the effect of a fuel’s chemicaland physical characteristics on tailpipe emissions is greatly reduced. For vehicles thatcomply with the latest emissions standards, most tailpipe air pollutant emissions reach very

148

https://www.agqm-

biodiesel.com/application/files/3415/2992/6037/WEB_EN_AGQM_0216_FREIGABEN.pdf

111low levels regardless of the fuel used. For older vehicles, however, fuel type can significantly
influence air pollutant emissions. Therefore, fuel selection is particularly relevant in many
emerging economies and developing countries with large urban agglomerations and older
vehicle fleets. Alternative fuels can help cleaning up ambient air, but they are not the
primary tool to reduce emissions.
The fuel effects on tailpipe emissions can be summarized as follows:•

Oxygenated components (alcohols, ethers, esters) tend to decrease carbon
monoxide, hydrocarbon and particulate emissions but increase emissions of nitrogenoxides•Methane provides soot-free combustion independent of the sophistication of theengine•Reducing aromatics (e.g., paraffinic renewable diesel) reduces particulate emissions
and exhaust toxicity•

Chemically simple fuels (e.g., alcohols, methane, propane) tend to form less toxic
emission components than complex fuels (gasoline, diesel), especially in engines
optimized for these alternative fuels

Figure 24 (light-duty vehicles) and Figure 25 (heavy-duty vehicles) present simplified
summaries of fuel effects on tailpipe emissions. The figures show that for present-time
vehicles, the effects are slender.
Ethanol generally results in lower air pollutant emissions when blended with gasoline, withthe level of emissions falling as the share of ethanol rises. This improvement is especiallynotable for particulate (PM) emissions, wherein lower emissions from high-ethanol blends
are achieved with direct-injection spark-ignition engines. Ethanol also reduces tailpipe
carbon oxide (CO) emissions; however, cold starting is more challenging with E85 than withgasoline, potentially raising volatile organic compound (VOC) emissions, and higher ethanol
blends can increase acetaldehyde emissions compared with gasoline.
Biomethane delivers low CO, PM and VOC emissions when used in a spark-ignition gas
engine. NOx emissions vary significantly depending on engine and exhaust after-treatment
technology; they are low for engines with a properly functioning three-way catalyst (TWC)and higher for less sophisticated lean-burn gas engines, for which there is some evidence ofelevated formaldehyde emissions.
FAME biodiesel used at high blend levels decreases CO, VOC and PM emissions,potentially up to 50% in less sophisticated engines. However, at high blends FAME
increases NOx emissions compared with fossil diesel as a result of higher oxygen content
112and subsequently higher combustion temperatures.
HVO has high ignition quality and the paraffinic nature of the fuel improves combustion andthus reduces CO, hydrocarbon (HC) and PM emissions compared with regular diesel. Unlike
FAME biodiesel, HVO also has potential to reduce NOx emissions up to 10%. Of all fuelssuitable for use in diesel vehicles, HVO delivers the lowest exhaust mutagenicity.

Figure 24: Fuel effects on tailpipe emissions of light-duty vehicles149.

Figure 25: Fuel effects on tailpipe emissions of heavy-duty vehicles33.

149

https://www.iea-

amf.org/app/webroot/files/file/other%20publications/Renewables%202018_biofuels%20and%20air%20qualit
y.pdf

113

Additional information on fuel properties, performance and vehicle
compatibility
The website of the IEA Technology Collaboration Programme on Advanced Motor Fuels(AMF, https://www.iea-amf.org/) contains a section named “Fuel Information”(https://www.iea-amf.org/content/fuel_information/fuel_info_home).
The "AMF Fuel Information System" focuses on the end-use aspects of advanced motor
fuels. Performance of vehicles, effects on emissions and compatibility with infrastructure areincluded, whereas resources, production and GHG emissions are excluded. When the enduse aspects are evaluated, the complex field of engine/after-treatment options, uncertainties
of measurement methods and incomparability of measurement campaigns have to be taken
into account. In the system, priority is given to new studies; however, these represent only
minor part of published studies.
The "AMF Fuel Information System" is based on information from AMF projects and otherreliable sources. Links to relevant AMF work are provided in all sections. The objective of the"AMF Fuel Information System" is to provide easy access to all end-use related aspects ofadvanced motor fuels.
The fuels and fuel components covered are:•Diesel and gasoline•

Bio/synthetic gasoline•

Bio/synthetic diesel (paraffins)•

Fatty Acid Esters (biodiesel)•

Oils and fats•

Oxygenates•

Ethanol•

Methanol•

Butanol•

Methane

•

LPG

•

DME

In addition, cross-cutting issues such as fuel comparisons and significance of emissions arecovered.
The following is a sample of information contained in the system (case ethanol and paraffinic
diesel):114

Ethanol is the dominant biocomponent in the gasoline market. Edible ethanol is produced byfermentation of sugar-containing feedstock. Production of fuel ethanol from cellulosic
feedstock is under commercialization phase. Industrial ethanol can be produced frompetrochemical ethylene by the acid-catalyzed hydration, but this cannot be used to meetbioenergy obligations. Ethanol is a monomolecular compound with narrow boiling point,whereas gasoline consists of hundreds of different hydrocarbon molecules. Ethanol isaromatic-, olefin- and sulfur-free compound. Oxygen content of ethanol is 35%.
General:•Ethanol properties•

Special engines for alcohol use

Ethanol for otto engines:•

Ethanol as low concentration “E10” fuel to be used in conventional gasoline cars.

•

Fuel ethers. Ethanol can be converted into e.g. ETBE, to be used in conventional
gasoline cars.

•

E85 fuel containing up to 85% ethanol in gasoline for special flexible-fuel vehicles(FFV).

Ethanol for diesel engines:•

Fatty Acid Ethanol Esters (FAEE) Ethanol can be converted into FAEE for low level
diesel blending.

•

Diesel engines for ethanol. Ethanol utilization in compression-ignition requires special
engines and/or changes in fuel, such as “Etamax D concept”.

Note: Ethanol as blending component in diesel fuel is not recommended for safety reasons.
However, IEA-AMF Annex 46 (Schramm, J. Ed. 2016) points out the reduced particle
emissions with this concept. Ethanol blending in diesel is also part of IEA-AMF Annex 10.
Paraffins are favorable components for diesel fuel. Diesel fuel itself contains paraffins inaddition to other hydrocarbon groups. However, diesel fuel contains also napthenics andaromatics, which are not so favorable for combustion. Paraffinic diesel fuel has normally very
high cetane number, no sulfur, nitrogen, oxygen nor aromatics. Paraffins can be producedwith various processes from fossil or renewable feedstocks. Synthetic fuels are produced bygasification and Fischer-Tropsch (FT) synthesis from natural gas (GTL) and coal (CTL).
Biomass-based BTL fuel is not commercially available, yet. Hydrotreating of oils and fats is acommercial process for producing renewable paraffinic diesel, abbreviated HVO. Today
more and more of HVO is produced from waste and residue fat fractions e.g. from animal
115

fats and non-food grade vegetable oil fractions. Paraffinic components for diesel fuel are
produced also from crude tall oil, a residue of pulp production.
Properties
•
•
•
•
•
•
•
•
•

Legislation andstandards
Density and energy
content
Cold properties
Cetane number
Distillation
Sulfur content andtrace elements
Stability and water
Lubricity
Measuring biocontent in fuelCompatibility••••

Emissions

How much paraffins canbe blended in diesel fuel?
Blending HVO/XTL
paraffins with FAME
Compatibility withmaterials
Storage and handling

•
•
•
•
•
•
•

Engine cleanliness andemission control devices
Power output, fuelconsumption, and CO2
Regulated emissions
Unregulated emissions
Optimizing engines for
HVO
Field trials
Summary

Summary
The compatibility of fuels with fuel infrastructure and vehicles, both the legacy fleet and new
vehicles, is a crucial issue. The full scale of compatibility means materials compatibility,
tolerance and vehicle compatibility over the lifetime of the vehicle and also vehicle
compliance. The latter means that when using the fuel (type) the vehicle fulfils all regulatory
requirements concerning pollutant emissions and safe vehicle use assessed on the basis oftests using regulated reference fuels for the fuel (type). For compliance, reference fuels andfuel standards have to be in place.
The easiest way to introduce biocomponents is to operate within the framework of existing
standards for gasoline and diesel fuel. However, when using traditional biocomponents suchas ethanol and FAME biodiesel, there are technical limitations, so-called “blending walls”, on
how much of these components can be added without compromising vehicle performanceand durability. Typically, standards for regular gasoline and diesel only allow blending
conventional biocomponents corresponding to an energy share 10 - 15%. Some activities tointroduce intermediate ethanol blends (E20, E25) are under way. However, for higher
substitution and more substantial decarbonization of transport, complementary actions areneeded.
Drop-in type fuels, fully fungible with conventional hydrocarbon fuels and compatible withexisting vehicles and fuel infrastructure, are one obvious solution. The degree of substitution
can be as high as 100%. Implementation can be fast, as no infrastructure or vehicle
modifications are needed. Paraffinic renewable diesel fuel, whether from hydrotreatment of116

oils and fats (HVO) or synthesis (BTL) is a kind of silver bullet for the diesel sector. For mostperformance criteria, paraffinic diesel is superior to regular diesel.
B100 is not a real drop-in type fuel, as it requires some changes in calibration, engine
hardware and maintenance schedules. Notwithstanding, some heavy-duty vehicle
manufacturers allow the use of B100 fuel in present-day sophisticated vehicles.
In the case of gasoline, there are in practice no superior renewable hydrocarbon drop-in
components, as bio-gasoline hydrocarbon compounds tend to have low octane numbers.
New blending components, either pure hydrocarbons, higher alcohols or ethers, could
alleviate the challenges.
The remaining option is special fuels for dedicated or adapted engines. Included in thiscategory are, e.g., gaseous fuels (methane, LPG), dimethyl ether (DME) and highconcentration alcohol fuels (E85, ED95). These fuels have a merit in chemically simple
structure, and in most cases, also inherently clean burning.
Dedicated vehicles and dedicated refueling infrastructure always pose the “chicken and egg
dilemma”, that is, simultaneously and in a balanced way, to build up the refuelinginfrastructure and the vehicle fleet. The efforts to introduce a completely new fuel on themarket are huge. DME has every now and then been forwarded as a promising alternativefor diesel engines. The IEA AMF Technology Collaboration Programme has contributed tothe development of an international ISO standard on DME for automotive applications150. In
spite of the potential for high efficiency and low CO2 emissions on a well-to-wheel basis,clean combustion and the existence of an international standard, DME has so far only beenused in some pilot projects.
The world population of natural gas vehicles exceeds 20 million units. Cleaned biogas,
biomethane, is a drop-in substitute for natural gas. Flex-fuel vehicles are still offered for themarkets in North and South America, but have in practice vanished from the European
market. FFVs are a cost-effective way of enabling the use of high concentration ethanol.
Regardless of the method to introduce biofuels, whether low-level blending, drop-in fuels or
special fuels for dedicated vehicles, fuel quality, vehicle/fuel compatibility and vehicle
compliance have to be maintained. Prerequisites are standards defining and securing fuelproperties and vehicles adapted to and certified for the fuels they are using. The fuel issimply not a parameter that can be decoupled from the rest of the system, which comprises

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of engine, lubricant, exhaust after-treatment system, refueling infrastructure and regulation
regarding safety and emissions.

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Abbreviations
ACEA

European Automobile Manufacturer´s Association

AGQM
ALIISA

Association Quality Management Biodiesel
Model used by VTT to calculate the future composition of vehicle fleets in this
study

AMF

Advanced Motor Fuels

APR

Aqueous phase reforming

ASTM

American Society for Testing and Materials

B5, B7,…

Diesel blends with x% FAME

BEV

Battery electric vehicle

BFG

Blast furnace gas

bio-LPG

Biobased liquefied petroleum gas

BOF gasBasic oxygen converter gas

CBIOCarbon Certificate, used in Brazilian regulation

CCS

Carbon capture and storage

CCU

Carbon capture and utilization

CEN

European Committee for Standardization

CFS

Clean Fuel Standard, Canadian regulation

CHP
CI

Combined heat and power
Carbon intensity, a measure of fossil GHG emissions over the life-cycle of a
fuel

COG

Coke oven gas

CONCAWE

Environmental Science for European Refining

CTL

Coal to liquid

DDGS

Dry distillers grains and solids, by-product of ethanol production

DME

Di-methyl ether

E5, E10,…
ED95

Gasoline blends with x% ethanol
Fuel quality on the market in the Northern European countries, consisting of
95% ethanol and 5% additives for the use in CI engines

EER

Energy Economy Ratio, used in Californian regulation

ETBE

Ethyl tert-butyl ether, ethanol-containing gasoline additive

EUR

Euro

EV

Electric vehicle

FAEE

Fatty acid ethyl ester

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FAME

Fatty acid methyl ester

FAO

Food and Agriculture Organization

FCC

Fluid catalytic cracking

FCEV

Fuel cell electric vehicle

FFA
FFV

Free fatty acids
Flex-fuel vehicle, capable of using either gasoline or high-blend ethanol (orpure hydrous ethanol in the case of Brazil)

FPO

Fast pyrolysis oil

FTFischer Tropsch

GGE

Gasoline-gallon-equivalent

GHG

greenhouse gases

GTL

Gas to liquids

GVW

Gross vehicle weightHD

Heavy duty

HDO

Hydrodeoxygenation

HDT

Heavy duty truck

HDV

Heavy duty vehicles

HEFA

Hydrotreated esters and fatty acids

HEV

Hybrid electric vehicle

HTL

Hydrothermal liquefaction

HVO

Hydrotreated vegetable oils

IEA

International Energy Agency

ILUC

Indirect land-use change

IRENAInternational Renewable Energy Agency

LBG

Liquefied biogas

LCA

Life-cycle assessment

LCFS

Low-carbon Fuel Standard, Californian regulation

LD

Light duty

LDTLight duty truck

LDV

Light duty vehicles

LPG

Liquefied petroleum gas (auto gas)

MCEC

Molten carbonate electrolyzer cell

MDT

Medium duty truck

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MSW

Municipal solid waste

MTBE

Methyl tert-butyl ether, methanol-containing gasoline additive

NEN

Netherland´s Standardization InstituteOEM

Original equipment manufacturer

PEM

Proton exchange membrane

PHEV

Plug-in hybrid electric vehicle

PM

Particulate matter

RDF

Refuse derived fuelRE

Renewable energy

RED

Renewable Energy Directive, EU regulation

RED-II

Recast of the Renewable Energy Directive, EU regulation

RenovaBio

Renova Bio, Brazilian regulation

RFS

Renewable Fuel Standard, US regulation

RIN

Renewable Identification Number, used in US regulation

RNG

Renewable natural gas

RON

Research Octane Number

RTFO

Renewable Transport Fuel Obligation, UK regulation

RVO

Renewable Volume Obligation, used in US regulation

SCR

Selective catalytic reduction, an exhaust after-treatment system

SGAB

Sub-Group on Advanced Biofuels

SHF

Separate hydrolysis and fermentation

SIP

Synthesized Iso-paraffinic fuel

SOEC

Solid oxide electrolyzer cell

SRC

Short rotation coppice

SRF

Solid recovered fuel

SSF

Simultaneous saccharification and fermentation

STF

Sustainable Transport Forum

TCP

Technology Collaboration Programme (of the IEA)

TRLTechnology Readiness LevelTTW CO2 emissions

Tank-to-wheel CO2 emissions, i.e. tailpipe emissions

TWC

Three-way catalyst

UCO

used cooking oil

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USD

United States (of America) Dollar

VOC

Volatile organic compoundWell-to-tank CO2 emissions, i.e. upstream emissions from fuel or electricity
production

WTT CO2 emissions
WTW CO2 emissions

Well-to-wheel CO2 emissions, i.e. WTT and TTW combined

WWFC

Worldwide Fuel Charter122