Editing IPCC:AR6/WGIII/Chapter-10 (section)

== 10.3 Transport Technology Innovations for Decarbonisation ==

<div id="h1-4-siblings" class="h1-siblings"></div>

This section focuses on vehicle technology and low-carbon fuel innovations to support decarbonisation of the transport sector. Figure 10.2 summarises the major pathways reviewed in this section. The advancements in energy carriers described in Figure 10.2 are discussed in greater detail in [[IPCC:Wg3:Chapter:Chapter-6|Chapter 6]] (Energy) and [[IPCC:Wg3:Chapter:Chapter-11|Chapter 11]] (Industry) but the review presented in this chapter highlights their application in the transport sector. This section pays attention to the advancements in alternative fuels, electric, and fuel cell technologies since AR5.

<div id="_idContainer019" class="Basic-Text-Frame"></div>

[[File:9c716ae13f2b169d1b619165abbbdc2d IPCC_AR6_WGIII_Figure_10_2.png]]

'''Figure 10.2 | Energy pathways for low-carbon transport technologies.''' Primary energy sources are shown in the far left, while the segments of the transport system are in the far right. Energy carriers and vehicle technologies are represented in the middle. Primary pathways are shown with solid lines, while dotted lines represent secondary pathways.

<div id="10.3.1" class="h2-container"></div>

<span id="alternative-fuels-an-option-for-decarbonising-internal-combustion-engines"></span>
=== 10.3.1 Alternative Fuels – An Option for Decarbonising Internal Combustion Engines ===

<div id="h2-9-siblings" class="h2-siblings"></div>

The average fuel consumption of new internal combustion engine (ICE) vehicles has improved significantly in recent years due to more stringent emissions regulations. However, improvements are now slowing down. The average fuel consumption of LDVs decreased by only 0.7 % between 2016 and 2017, reaching 7.2 litres of gasoline-equivalent (Lg-eq) per 100 km in 2017, much slower than the 1.8 % improvement per year between 2005 and 2016 ( [[#GFEI--2020|GFEI 2020]] ). Table 10.4 summarises recent and forthcoming improvements to ICE technologies and their effect on emissions from these vehicles. However, these improvements are not sufficient to meet deep decarbonisation levels in the transport sector. While there is significant and growing interest in electric and fuel-cell vehicles, future scenarios indicate that a large number of LDV may continue to be operated by ICE in conventional, hybrid, and plug-in hybrid configurations over the next 30 years ( [[#IEA--2019a|IEA 2019a]] ), unless they are regulated away through ICE vehicle sales bans (as some nations have announced) ( [[#IEA--2021a|IEA 2021a]] ). Moreover, ICE technologies are likely to remain the prevalent options for shipping and aviation. Thus, reducing CO 2 and other emissions from ICEs through the use of low-carbon or zero-carbon fuels is essential to a balanced strategy for limiting atmospheric pollutant levels. Such alternative fuels for ICE vehicles include natural gas-based fuels, biofuels, ammonia, and other synthetic fuels.

'''Table 10.4 | Engine technologies to reduce emissions from light-duty ICE vehicles and their implementation stage.''' Table nomenclature: GDI = Gasoline direct injection, VVT = Variable valve technology, CDA = Cylinder deactivation, CR = compression ratio, GDCI = Gasoline direct injection compression ignition, EGR = exhaust gas recirculation, RCCI = Reactivity controlled compression ignition, GCI = Gasoline compression ignition. Source: [[#Joshi--2020|Joshi (2020)]] .

{| class="wikitable"
|-
| '''Implementation stage'''

| '''Engine technology'''

| '''CO''' 2 '''reduction'''

'''(%)'''

|-
| Implemented

| Baseline: GDI, turbo, stoichiometry

| 0

|-
| rowspan="12"| Development

| Atkinson cycle (+ VVT)

| 3–5

|-
| Dynamic CDA + Mild hybrid or Miller

| 10–15

|-
| Lean-burn GDI

| 10–20

|-
| Variable CR

| 10

|-
| Spark assisted GCI

| 10

|-
| GDCI

| 15–25

|-
| Water injection

| 5–10

|-
| Pre-chamber concepts

| 15–20

|-
| Homogeneous lean

| 15–20

|-
| Dedicated EGR

| 15–20

|-
| 2-stroke opposed-piston diesel

| 25–35

|-
| RCCI

| 20–30

|}

'''Natural Gas.''' Natural gas could be used as an alternative fuel to replace gasoline and diesel. Natural gas in vehicles can be used as compressed natural gas (CNG) and liquefied natural gas (LNG). CNG is gaseous at relatively high pressure (10 to 25 megapascal (MPa)) and temperature (–40 to 30°C). In contrast, LNG is used in liquid form at relatively low pressure (0.1 MPa) and temperature (–160°C). Therefore, CNG is particularly suitable for commercial vehicles and light- to medium-duty vehicles, whereas LNG is better suited to replace diesel in HDVs ( [[#Dubov--2020|Dubov et al. 2020]] ; [[#Dziewiatkowski--2020|Dziewiatkowski et al. 2020]] ; [[#Yaïci--2021|Yaïci and Ribberink 2021]] ). CNG vehicles have been widely deployed in some regions, particularly in Asian-Pacific countries. For example, there are about 6 million CNG vehicles in China, the most of any country ( [[#Qin--2020|Qin et al. 2020]] ). However, only 20% of vehicles that operate using CNG were originally designed as CNG vehicles, with the rest being gasoline-fuelled vehicles that have been converted to operate with CNG ( [[#Chala--2018|Chala et al. 2018]] ).

Natural gas-based vehicles have certain advantages over conventional fuel-powered ICE vehicles, including lower emissions of criteria air pollutants, no soot or particulate, low carbon to Hydrogen ratio, moderate noise, a wide range of flammability limits, and high octane numbers ( [[#Kim--2019|Kim 2019]] ; [[#Bayat--2020|Bayat and Ghazikhani 2020]] ). Furthermore, the technology readiness level (TRL) of natural gas vehicles is very high (TRL 8–9), with direct modification of existing gasoline and diesel vehicles possible ( [[#Transport%20and%20Environment--2018|Transport and Environment 2018]] ; [[#Peters--2021|Peters et al. 2021]] ; [[#Sahoo--2021|Sahoo and Srivastava 2021]] ). On the other hand, methane emissions from the natural gas supply chain and tailpipe CO 2 emissions remain a significant concern ( [[#Trivedi--2020|Trivedi et al. 2020]] ). As a result, natural gas as a transition transportation fuel may be limited due to better alternative options being available and due to regulatory pressure to decarbonise the transport sector rapidly. For example, the International Maritime Office (IMO) has set a target of 40% less carbon intensity in shipping by 2030, which cannot be obtained by simply switching to natural gas.

'''Biofuels.''' Since AR5, the faster than anticipated adoption of electromobility, primarily for LDVs, has partially shifted the debate around the primary use of biofuels from land transport to the shipping and aviation sectors ( [[#IEA--2017a|IEA 2017a]] ; [[#Davis--2018|Davis et al. 2018]] ). At the same time, other studies highlight that biofuels may have to complement electromobility in road transport, particularly in developing countries, offering relevant mitigation opportunities in the short- and mid-term (up to 2050) ( [[#IEA--2021b|IEA 2021b]] ). An important advantage of biofuels is that they can be converted into energy carriers compatible with existing technologies, including current powertrains and fuel infrastructure. Also, biofuels can diversify the supply of transport fuel, raise energy self-sufficiency in many countries, and be used as a strategy to diversify and strengthen the agro-industrial sector ( [[#Puricelli--2021|Puricelli et al. 2021]] ). The use of biofuels as a mitigation strategy is driven by a combination of factors, including not only the costs and technology readiness levels of the different biofuel conversion technologies, but also the availability and costs of both biomass feedstocks and alternative mitigation options, and the relative speed and scale of the energy transition in energy and transport sectors (Box 10.2).

Many studies have addressed the lifecycle emissions of biofuel conversion pathways for land transport, aviation, and marine applications ( [[#Koeble--2017|Koeble et al. 2017]] ; [[#Staples--2018|Staples et al. 2018]] ; [[#Tanzer--2019|Tanzer et al. 2019]] ). Bioenergy technologies generally struggle to compete with existing fossil fuel-based ones because of the higher costs involved. However, the extent of the cost gap depends critically on the availability and costs of biomass feedstock ( [[#IEA--2021b|IEA 2021b]] ). Ethanol from corn and sugarcane is commercially available in countries such as Brazil and the US. Biodiesel from oil crops and hydro-processed esters and fatty acids are available in various countries, notably in Europe and parts of Southeast Asia. On the infrastructure side, biomethane blending is being implemented in some regions of the US and Europe, particularly in Germany, with the help of policy measures ( [[#IEA--2021b|IEA 2021b]] ). While many of these biofuel conversion technologies could also be implemented using seaweed feedstock options, these value chains are not yet mature ( [[#Jiang--2016|Jiang et al. 2016]] ).

Technologies to produce advanced biofuels from lignocellulosic feedstocks have suffered from slow technology development and are still struggling to achieve full commercial scale. Their uptake is likely to require carbon pricing and/or other regulatory measures, such as clean fuel standards in the transport sector or blending mandates. Several commercial-scale advanced biofuels projects are in development in many parts of the world, encompassing a wide selection of technologies and feedstock choices, including carbon capture and sequestration (CCS) that supports carbon dioxide removal. The success of these projects is vital to moving forward the development of advanced biofuels and bringing many of the advanced biofuels value chains closer to the market ( [[#IEA--2021b|IEA 2021b]] ). Finally, biofuel production and distribution supply chains involve notable transport and logistical challenges that need to be overcome ( [[#Mawhood--2016|Mawhood et al. 2016]] ; [[#Skeer--2016|Skeer et al. 2016]] ; [[#IEA--2017a|IEA 2017a]] ; [[#Puricelli--2021|Puricelli et al. 2021]] ).

Table 10.5 summarises performance data for different biofuel technologies, while Figure 10.3 shows the technology readiness levels.

'''Table 10.5 | Ranges of efficiency, GHG emissions, and relative costs of selected biofuel conversion technologies for road, marine, and aviation biofuels.'''

{| class="wikitable"
|-
| '''Main application'''

| '''Conversion technology'''

| '''Energy efficiency of conversion''' a

| '''GHG emissions of conversion process (gCO''' 2 '''-eq per MJ of fuel)''' b

| '''Relative cost of conversion process'''

|-
| Road

| Lignocellulosic ethanol

| 35% c

| 5 d

| Medium

|-
| Road/aviation

| Gasification and Fischer-Tropsch synthesis

| 57% e

| &lt;1 d

| High

|-
| Road

| Ethanol from sugar and starch

| 60–70% f

| 1–31 d

| Low

|-
| Road

| Biodiesel from oil crops

| 95% g

| 12–30 d

| Low

|-
| Marine

| Upgraded pyrolysis oil

| 30–61% h

| 1–4 h

| Medium

|-
| Aviation/marine

| Hydro-processed esters and fatty acids

| 80% i

| 3 i

| Medium

|-
| Aviation

| Alcohol to jet

| 90% j

| &lt;1 k

| High

|-
| Road/marine

| Biomethane from residues

| 60% l

| n/a

| Low

|-
| Marine/aviation

| Hydrothermal liquefaction

| 35–69% h

| &lt;1 h

| High

|-
| Aviation

| Sugars to hydrocarbons

| 65% m

| 15 m

| High

|-
| Road

| Gasification and syngas fermentation

| 40% n

| 30–40 n

| High

|}

Notes: a Calculated as liquid fuels output divided by energy in feedstock entering the conversion plant; b GHG emissions here refers only to the conversion process. Impacts form the different biomass options are not included here as they are addressed in Chapter 7; c [[#Olofsson--2017|Olofsson et al. (2017)]] ; d [[#Koeble--2017|Koeble et al. (2017)]] ; e [[#Simell--2014|Simell et al. (2014)]] ; f [[#de%20Souza%20Dias--2015|de Souza Dias et al. (2015)]] ; g [[#Castanheira--2015|Castanheira et al. (2015)]] ; h [[#Tanzer--2019|Tanzer et al. (2019)]] ; i [[#Klein--2018|Klein et al. (2018)]] ; j Narula et al. (2017); k [[#de%20Jong--2017|de Jong et al. (2017)]] ; l [[#Salman--2017|Salman et al. (2017)]] ; m [[#Moreira--2014|Moreira et al. (2014)]] ; [[#Roy--2015|Roy et al. (2015)]] ; [[#Handler--2016|Handler et al. (2016)]] ; n [[#Salman--2017|Salman et al. (2017)]] ; [[#Moreira--2014|Moreira et al. (2014)]] ; [[#Roy--2015|Roy et al. (2015)]] ; [[#Handler--2016|Handler et al. (2016)]] .

<div id="_idContainer022" class="Basic-Text-Frame"></div>

[[File:3c805cf0be412a504291c2d8f8af6da3 IPCC_AR6_WGIII_Figure_10_3.png]]

'''Figure 10.3 | Commercialisation status of selected biofuels conversion technologies.''' The grey boxes represent the current technology readiness level of each conversion technology. Source: based on [[#Mawhood--2016|Mawhood et al. (2016)]] , [[#Skeer--2016|Skeer et al. (2016)]] , [[#IEA--2017a|IEA (2017a)]] , and [[#Puricelli--2021|Puricelli et al. (2021)]] .

Within the aviation sector, jet fuels produced from biomass resources (so-called sustainable aviation fuels, or SAF) could offer significant climate mitigation opportunities under the right policy circumstances. Despite the growing interest in aviation biofuels, demand and production volumes remain negligible compared to conventional fossil aviation fuels. Nearly all flights powered by biofuels have used fuels derived from vegetable oils and fats, and the blending level of biofuels into conventional aviation fuels for testing is up to 50% today ( [[#Mawhood--2016|Mawhood et al. 2016]] ). To date, only one facility in the US is regularly producing sustainable aviation fuels based on waste oil feedstocks. The potential to scale up bio-based SAF volumes is severely restricted by the lack of low-cost and sustainable feedstock options (Chapter 7). Lignocellulosic feedstocks are considered to have great potential for the production of financially competitive bio-based SAF in many regions. However, production facilities involve significant capital investment and estimated levelised costs are typically more than twice the selling price of conventional jet fuel. In some cases (notably for vegetable oils), the feedstock price is already higher than that of fossil jet fuel ( [[#Mawhood--2016|Mawhood et al. 2016]] ). Some promising technological routes for producing SAF from lignocellulosic feedstocks are below technology readiness level (TRL) 6 (pilot scale), with just a few players involved in the development of these technologies. Although it would be physically possible to address the mid-century projections for substantial use of biofuels in the aviation sector (according to the International Energy Agency (IEA) and other sectoral organisations ( [[#ICAO--2017|ICAO 2017]] )), this fuel deployment scale could only be achieved with very large capital investments in bio-based SAF production infrastructure, and substantial policy support.

In comparison to the aviation sector, the prospects for technology deployment are better in the shipping sector. The advantage of shipping fuels is that marine engines have a much higher operational flexibility on a mix of fuels, and shipping fuels do not need to undergo as extensive refining processes as road and aviation fuels to be considered drop-in. However, biofuels in marine engines have only been tested at an experimental or demonstration stage, leaving open the question about the scalability of the operations, including logistics issues. Similar to the aviation sector, securing a reliable, sustainable biomass feedstock supply and mature processing technologies to produce price-competitive biofuels at a large scale remains a challenge for the shipping sector ( [[#Hsieh--2017|Hsieh and Felby 2017]] ). Other drawbacks include industry concerns about oxidation, storage, and microbial stability for less purified or more crude biofuels. Assuming that biofuels are technically developed and available for the shipping sector in large quantities, a wider initial introduction of biofuels in the sector is likely to depend upon increased environmental regulation of particulate and GHG emissions. Biofuels may also offer a significant advantage in meeting ambitious sulphur emission reduction targets set by the sectoral organisations. More extensive use of marine biofuels will most likely be first implemented in inner-city waterways, inland river freight routes, and coastal green zones. Given the high efficiency of the diesel engine, a large-scale switch to a different standard marine propulsion method in the near to medium-term future seems unlikely . Thus, much of the effort has been placed on developing biofuels compatible with diesel engines. So far, biodiesel blends look promising, as it is used in land transport. Hydrotreated vegetable oil (HVO) is also a technically good alternative and is compatible with current engines and supply chains, while the introduction of multifuel engines may open the market for ethanol fuels ( [[#Hsieh--2017|Hsieh and Felby 2017]] ).

'''Ammonia.''' At room temperature and atmospheric pressure, ammonia is a colourless gas with a distinct odour. Due to relatively mild conditions for liquefaction, ammonia is transferred and stored as a liquefied or compressed gas and has been used as an essential industrial chemical resource for many products. In addition, since ammonia does not contain carbon, it has attracted attention as a carbon-neutral fuel that can also improve combustion efficiency ( [[#Gill--2012|Gill et al. 2012]] ). Furthermore, ammonia could also serve as a hydrogen carrier and be used in fuel cells. These characteristics have driven increased interest in the low-carbon production of ammonia, which would have to be coupled to low-carbon hydrogen production (with low-carbon electricity providing the needed energy or with CCS).

For conventional internal combustion engines, the use of ammonia remains challenging due to the relatively low burning velocity and high ignition temperature. Therefore, [[#Frigo--2014|Frigo and Gentili (2014)]] have suggested a dual-fuelled spark ignition engine operated by liquid ammonia and hydrogen, where hydrogen is generated from ammonia using the thermal energy of exhaust gas. On the other hand, the high-octane number of ammonia means good knocking resistance of spark ignition engines and is promising for improving thermal efficiency. For compression ignition engines, the high-ignition temperature of ammonia requires a high compression ratio, causing an increase in mechanical friction. Since [[#Gray--1966|Gray et al. (1966)]] , many studies have shown that the compression ratio can be reduced by mixing ammonia with secondary fuels such as diesel and hydrogen with low self-ignition temperatures, as summarised by [[#Dimitriou--2020|Dimitriou and Javaid (2020)]] . Using a secondary fuel with a high cetane number and the adoption of a suitable fuel injection timing has enabled highly efficient combustion of compression ignition engines in the dual fuel mode with ammonia ratios up to 95% ( [[#Dimitriou--2020|Dimitriou and Javaid 2020]] ). One major challenge for realising an ammonia-fuelled engine is the reduction of unburned ammonia, as described in [[IPCC:Wg3:Chapter:Chapter-6#6.4.5|Section 6.4.5]] ( [[#Reiter--2011|Reiter and Kong 2011]] ). Processes being examined include the use of exhaust gas recirculation (EGR) (Pochet et al. 2017) and after treatment systems. However, these processes require space, which is a constraint for LDVs and air transport but more practical for ships. Shipbuilders are developing an ammonia engine based on the existing diesel dual-fuel engine to launch a service in 2025 ( [[#Brown--2019|Brown 2019]] ; [[#MAN-ES--2019|MAN-ES 2019]] ). Ammonia could therefore contribute significantly to decarbonisation in the shipping sector ( [[#10.6|Section 10.6]] ), with potential niche applications elsewhere.

'''Synthetic fuels.''' Synthetic fuels can contribute to transport decarbonisation through synthesis from electrolytic hydrogen produced with low-carbon electricity or hydrogen produced with CCS, and captured CO 2 using the Fischer-Tropsch process ( [[#Liu--2020a|Liu et al. 2020a]] ). Due to similar properties of synthetic fuels to those of fossil fuels, synthetic fuels can reduce GHG emissions in both existing and new vehicles without significant changes to the engine design. While the Fischer-Tropsch process is a well-established technology ( [[#Liu--2020a|Liu et al. 2020a]] ), low-carbon synthetic fuel production is still at the demonstration stage. Even though their production costs are expected to decline in the future due to lower renewable electricity prices, increased scale of production, and learning effects, synthetic fuels are still up to three times more expensive than conventional fossil fuels ( [[IPCC:Wg3:Chapter:Chapter-6#6.6.2.4|Section 6.6.2.4]] ). Furthermore, since the production of synthetic fuels involves thermodynamic conversion loss, there is a concern that the total energy efficiency is lower than that of electric vehicles ( [[#Yugo--2019|Yugo and Soler 2019]] ). Given these high costs and limited scales, the adoption of synthetic fuels will likely focus on the aviation, shipping, and long-distance road transport segments, where decarbonisation by electrification is more challenging. In particular, synthetic fuels are considered promising as an aviation fuel ( [[#10.5|Section 10.5]] ).

<div id="box-10.2" class="h2-container box-container"></div>

<span id="box-10.2-bridging-land-use-and-feedstock-conversion-footprints-for-biofuels"></span>
=== Box 10.2 | Bridging Land Use and Feedstock Conversion Footprints for Biofuels ===

<div id="h2-1-siblings" class="h2-siblings"></div>

Under specific conditions, biofuels may represent an important climate mitigation strategy for the transport sector ( [[#Daioglou--2020|Daioglou et al. 2020]] ; [[#Muratori--2020|Muratori et al. 2020]] ). Both the IPCC Special Report on Global Warming of 1.5°C and the IPCC Special Report on Climate Change and Land highlighted that biofuels could be associated with climate mitigation co-benefits and adverse side effects to many SDGs. These side effects depend on context-specific conditions, including deployment scale, associated land-use changes and agricultural management practices ( [[IPCC:Wg3:Chapter:Chapter-7#7.4.4|Section 7.4.4]] and Box 7.10). There is broad agreement in the literature that the most important factors in determining the climate footprint of biofuels are the land use and land-use change characteristics associated with biofuel deployment scenarios ( [[#Elshout--2015|Elshout et al. 2015]] ; [[#Daioglou--2020|Daioglou et al. 2020]] ). This issue is covered in more detail in Box 7.1. While the mitigation literature primarily focuses on the GHG-related climate forcings, note that land is an integral part of the climate system through multiple geophysical and geochemical mechanisms (albedo, evaporation, etc.). For example, Sections 2.2.7 and 7.3.4 in the AR6 WGI report indicate that geophysical aspects of historical land-use change outweigh the geochemical effects, leading to a net cooling effect. The land-related carbon footprints of biofuels presented in Sections 10.4–10.6 are adopted from [[IPCC:Wg3:Chapter:Chapter-7|Chapter 7]] ( [[IPCC:Wg3:Chapter:Chapter-7#7.4.4|Section 7.4.4]] , Box 7, and Figure 7.1). The results show how the land-related footprint increases due to an increased outtake of biomass, as estimated with different models that rely on global supply scenarios of biomass for energy and fuel of 100 exajoules (EJ). The integrated assessment models and scenarios used include the EMF 33 scenarios (IAM-EMF33), from partial models with constant land cover (PM-CLC), and from partial models with natural regrowth (PM-NGR). These results are combined with both biomass cultivation emission ranges for advanced biofuels aligned with [[#Koeble--2017|Koeble et al. (2017)]] , [[#El%20Akkari--2018|El Akkari et al. (2018)]] , [[#Jeswani--2020|Jeswani et al. (2020)]] , and [[#Puricelli--2021|Puricelli et al. (2021)]] and conversion efficiencies and conversion phase emissions as described in Table 10.5. The modelled footprints resulting from land-use changes related to delivering 100 EJ of biomass at global level are in the range of 3–77 gCO 2 -eq per MJ of advanced biofuel (median 38 gCO 2 -eq MJ –1 ) at an aggregate level for Integrated Assessment Models (IAMs) and partial models with constant land cover ( [[#Daioglou--2020|Daioglou et al. 2020]] ; [[#Rose--2020|Rose et al. 2020]] ). The results for partial models with natural regrowth are much higher (91–246 CO 2 -eq MJ –1 advanced biofuel). The latter ranges may appear in contrast with the results from the scenario literature in [[#10.7|Section 10.7]] , where biofuels play a role in many scenarios compatible with low warming levels. This contrast is a result of different underlying modelling practices. The general modelling approach used for the scenarios in the AR6 database accounts for the land-use change and all other GHG emissions along a given transformation trajectory, enabling assessments of the warming level incurred. The results labelled ‘EMF33’ and ‘partial models with constant land cover’ are obtained with this modelling approach. The results in the category ‘partial models with natural regrowth’ attribute additional CO 2 emissions to the bioenergy system, corresponding to estimated uptake of CO 2 in a counterfactual scenario where land is not used for bioenergy, but instead subject to natural vegetation regrowth. While the partial analysis provides insights into the implications of alternative land-use strategies, such analysis does not identify the actual emissions of bioenergy production. As a result, the partial analysis is not compatible with the identification of warming levels incurred by an individual transformation trajectory, and therefore not aligned with the general approach applied for the scenarios in the AR6 database.

More details on land-use change impacts and the potential to deliver the projected demands of biofuels at the global level are further addressed in Chapter 7. While, in general, the above results cover most of the variety of GHG range intensities of biofuel options presented in the literature, the more specific life cycle assessment (LCA) literature should be consulted when considering specific combinations of biomass feedstock and conversion technologies in specific regions.

<div id="10.3.2" class="h2-container"></div>

<span id="electric-technologies"></span>
=== 10.3.2 Electric Technologies ===

<div id="h2-10-siblings" class="h2-siblings"></div>

Widespread electrification of the transport sector is likely crucial for reducing transport emissions and depends on appropriate electrical energy storage systems (EES). However, large-scale diffusion of EES depends on improvements in energy density (energy stored per unit volume), specific energy (energy stored per unit weight), and costs ( [[#Cano--2018|Cano et al. 2018]] ). Recent trends suggest EES-enabled vehicles are on a path to becoming the leading technology for LDVs, but their contribution to heavy-duty freight is more uncertain.

'''Electrochemical storage of light and medium-duty vehicles.''' Electrochemical storage, i.e., batteries, are one of the most promising forms of energy storage for the transport sector and have dramatically improved in their commerciality since AR5. Rechargeable batteries are of primary interest for applications within the transport sector, with a range of mature and emerging chemistries able to support the electrification of vehicles. The most significant change since AR5 and SPR1.5 is the dramatic rise in lithium-ion batteries (LIB), which has enabled electromobility to become a major feature of decarbonisation.

Before the recent growth in market share of LIBs, lead-acid batteries, nickel batteries, high-temperature sodium batteries, and redox flow batteries were of particular interest for the transport sector ( [[#Placke--2017|Placke et al. 2017]] ). Due to their low costs, lead-acid batteries have been used in smaller automotive vehicles, e.g., e-scooters and e-rickshaws ( [[#Dhar--2017|Dhar et al. 2017]] ). However, their application in electric vehicles will be limited due to their low specific energy ( [[#Andwari--2017|Andwari et al. 2017]] ). Nickel-metal hydride (NiMH) batteries have a better energy density than lead-acid batteries and have been well optimised for regenerative braking ( [[#Cano--2018|Cano et al. 2018]] ). As a result, NiMH batteries were the battery of choice for hybrid electric vehicles (HEVs). Ni-Cadmium (NiCd) batteries have energy densities lower than NiMH batteries and cost around ten times more than lead-acid batteries (Table 6.5). For this reason, NiCd batteries do not have major prospects within automotive applications. There are also no examples of high-temperature sodium or redox flow batteries being used within automotive applications.

Commercial application of LIBs in automotive applications started around 2000 when the price of LIBs was more than USD1000 per kWh ( [[#Schmidt--2017|Schmidt et al. 2017]] ). By 2020, the battery manufacturing capacity for automotive applications was around 300 GWh per year ( [[#IEA--2021a|IEA 2021a]] ). Furthermore, by 2020, the average battery pack cost had come down to USD137 per kWh, a reduction of 89% in real terms since 2010 ( [[#Henze--2020|Henze 2020]] ). Further improvements in specific energy, energy density (Nykvist et al. 2015; [[#Placke--2017|Placke et al. 2017]] ) and battery service life ( [[#Liu--2017|Liu et al. 2017]] ) of LIBs are expected through additional design optimisation (Table 6.5). These advances are expected to lead to EVs with even longer driving ranges, further supporting the uptake of LIBs for transport applications ( [[#Cano--2018|Cano et al. 2018]] ). However, the performance of LIBs under freezing and high temperatures is a concern ( [[#Liu--2017|Liu et al. 2017]] ) for reliability. Auto manufacturers have some pre-heating systems for batteries to see that they perform well in very cold conditions ( [[#Wu--2020|Wu et al. 2020]] ).

For EVs sold in 2018, the material demand was about 11 kilotonnes (kt) of optimised lithium, 15 kt of cobalt, 11 kt of manganese, and 34 kt of nickel ( [[#IEA--2019a|IEA 2019a]] ; [[#IEA--2021a|IEA 2021a]] ). IEA projections for 2030 in the EV 30@30 scenario show that the demand for these materials would increase by 30 times for lithium and around 25 times for cobalt. While there are efforts to move away from expensive materials such as cobalt ( [[#IEA--2019a|IEA 2019a]] ; [[#IEA--2021a|IEA 2021a]] ), dependence on lithium will remain, which may be a cause of concern ( [[#Olivetti--2017|Olivetti et al. 2017]] ; [[#You--2018|You and Manthiram 2018]] ). A more detailed discussion on resource constraints for lithium is provided in Box 10.6.

Externalities from resource extraction are another concern, though current volumes of lithium are much smaller than other metals (steel, aluminium). As a result, lithium was not even mentioned in UNEP’s global resource outlook ( [[#IRP--2019|IRP 2019]] ). Nonetheless, it is essential to manage demand and limit externalities since the demand for lithium is going to increase many times in the future. Reuse of LIBs used in EVs for stationary energy applications can help in reducing the demand for LIBs. However, the main challenges are the difficulty in accessing the information on the health of batteries to be recycled and technical problems in remanufacturing the batteries for their second life ( [[#Ahmadi--2017|Ahmadi et al. 2017]] ). Recycling lithium from used batteries could be another possible supply source (Winslow et al. 2018). While further R&amp;D is required for commercialisation (Ling et al., 2018), recent efforts at recycling LIBs are very encouraging ( [[#Ma--2021|Ma et al. 2021]] ). The standardisation of battery modules and packaging within and across vehicle platforms, increased focus on design for recyclability, and supportive regulation are important to enable higher recycling rates for LIBs ( [[#Harper--2019|Harper et al. 2019]] ).

Several next-generation battery chemistries are often referred to as post-LIBs ( [[#Placke--2017|Placke et al. 2017]] ). These chemistries include metal-sulphur, metal-air, metal-ion (besides Li), and all-solid-state batteries. The long development cycles of the automotive industry ( [[#Cano--2018|Cano et al. 2018]] ) and the advantages of LIBs in terms of energy density and cycle life (Table 6.5) mean that it is unlikely that post-LIB technologies will replace LIBs in the next decade. However, lithium-sulphur, lithium-air, and zinc-air have emerged as potential alternatives for LIBs. These emerging chemistries may also be used to supplement LIBs in dual-battery configurations, to extend the driving range at lower costs or with higher energy density ( [[#Cano--2018|Cano et al. 2018]] ). Lithium-sulphur (Li-S) batteries have a lithium metal anode with a higher theoretical capacity than lithium-ion anodes and much lower-cost sulphur cathodes relative to typical Li-ion insertion cathodes ( [[#Manthiram--2014|Manthiram et al. 2014]] ). As a result, Li-S batteries are much cheaper than LIB to manufacture and have a higher energy density (Table 6.5). Conversely, these batteries face challenges from sulphur cathodes, such as low conductivity of the sulphur and lithium sulphide phases, and the relatively high solubility of sulphur species in common lithium battery electrolytes, leading to low cycle life ( [[#Cano--2018|Cano et al. 2018]] ). Lithium-air batteries offer a further improvement in specific energy and energy density above Li–S batteries owing to their use of atmospheric oxygen as a cathode in place of sulphur. However, their demonstrated cycle life is much lower (Table 6.5). Lithium-air batteries also have low specific power. Therefore, lithium-air require an extra battery for practical applications ( [[#Cano--2018|Cano et al. 2018]] ). Finally, zinc–air batteries could more likely be used in future EVs because of their more advanced technology status and higher practically achievable energy density ( [[#Fu--2017|Fu et al. 2017]] ). Like Li-air batteries, their poor specific power and energy efficiency will probably prevent zinc-air batteries from being used as a primary energy source for EVs. Still, they could be promising when used in a dual-battery configuration ( [[#Cano--2018|Cano et al. 2018]] ).

The technological readiness of batteries is a crucial parameter in the advancement of EVs ( [[#Manzetti--2015|Manzetti and Mariasiu 2015]] ). Energy density, power density, cycle life, calendar life, and the cost per kWh are the pertinent parameters for comparing the technological readiness of various battery technologies ( [[#Manzetti--2015|Manzetti and Mariasiu 2015]] ; [[#Andwari--2017|Andwari et al. 2017]] ; [[#Lajunen--2018|Lajunen et al. 2018]] ). Table 6.5 provides a summary of the values of these parameters for alternative battery technologies. LIBs comprehensively dominate the other battery types and are at a readiness level where they can be applied for land transport applications (cars, scooters, electrically-assisted cycles) and at battery pack costs below USD150 per kWh, making EVs cost-competitive with conventional vehicles ( [[#Nykvist--2019|Nykvist et al. 2019]] ). In 2020 the stock of battery electric LDVs had crossed the 10 million mark ( [[#IEA--2021a|IEA 2021a]] ). [[#Schmidt--2017|Schmidt et al. (2017)]] project that the cost of a battery pack for LIBs will reach USD100 per kWh by 2030, but more recent trends show this could happen much earlier. For example, according to IEA, battery pack costs could be as low as USD80 per kWh by 2030 ( [[#IEA--2019a|IEA 2019a]] ). In addition, there are clear trends that now vehicle manufacturers are offering vehicles with bigger batteries, greater driving ranges, higher top speeds, faster acceleration, and all size categories ( [[#Nykvist--2019|Nykvist et al. 2019]] ). In 2020 there were over 600,000 battery electric buses and over 31,000 battery electric trucks operating globally ( [[#IEA--2021a|IEA 2021a]] ).

LIBs are not currently envisaged to be suitable for long-haul transport. However, several battery technologies are under development (Table 6.5), which could further enhance the competitiveness of EVs and expand their applicability to very short-haul aviation and ships, especially smaller vehicles. Li-S, Li-air, and Zn-air hold the highest potential for these segments ( [[#Cano--2018|Cano et al. 2018]] ). All three of these technologies rely on making use of relatively inexpensive elements, which can help bring down battery costs ( [[#Cano--2018|Cano et al. 2018]] ). The main challenge these technologies face is in terms of the cycle life. Out of the three, Li-S has already been used for applications in unmanned aerial vehicles ( [[#Fotouhi--2017|Fotouhi et al., 2017]] ) due to relatively high specific energy (almost double the state of the art LIBs). However, even with low cycle life, Li-air and Zn-air hold good prospects for commercialisation as range extender batteries for long-range road transport and with vehicles that are typically used for city driving ( [[#Cano--2018|Cano et al. 2018]] ).

'''Alternative electricity storage technologies for heavy-duty transport.''' While LIBs described in the previous section are driving the electrification of LDVs, their application to railways, aviation, ships, and large vehicles faces challenges due to the higher power requirements of these applications. The use of a capacitor with a higher power density than LIBs could be suitable for the electrification of such vehicles. It is one of the solutions for regenerating large and instantaneous energy from regenerative brakes. Classical capacitors generally show more attractive characteristics in power density (8000–10,000 watts per kilogram (W/kg)) than batteries. However, the energy density is poor (1–4 watt-hours per kilogram (Wh/kg)) compared to batteries, and there is an issue of self-discharge ( [[#González--2016|González et al. 2016]] ; [[#Poonam--2019|Poonam et al. 2019]] ). To improve the energy density, electrochemical double layer capacitors (EDLCs; supercapacitor) and hybrid capacitors (10–24 Wh/kg, 900–9000 W/kg at the product level) such as Li-ion capacitors have been developed. The highest energy density of the LIC system (100–140 Wh/kg in the research stage) are approaching that of the Li-ion battery systems (80–240 Wh/kg in the product stage) ( [[#Naoi--2012|Naoi et al. 2012]] ; [[#Panja--2020|Panja et al. 2020]] ). Examples of effective use of capacitors include a 12-tonne truck with a capacitor-based kinetic energy recovery system that has been reported to save up to 32% of the fuel use of a standard truck ( [[#Kamdar--2017|Kamdar 2017]] ). Similarly, an EDLC bank applied to electric railway systems has been shown to result in a 10% reduction in power consumption per day ( [[#Takahashi--2017|Takahashi et al. 2017]] ). Finally, systems in which capacitors are mounted on an electric bus for charging at a stop have been put into practical use, for example by a trackless tram ( [[#Newman--2019|Newman et al. 2019]] ). At the bus stop, the capacitor is charged at 600 kW for 10 about 40 seconds, which provides enough power for about 5 to 10 km ( [[#Newman--2019|Newman et al. 2019]] ). In addition, more durable capacitors can achieve a longer life than LIB systems ( [[#ADB--2018|ADB 2018]] ).

Hybrid energy storage (HES) systems, which combine a capacitor and a battery, achieve both high power and high energy, solving problems such as capacity loss of the battery and self-discharge of the capacitor. In these systems, the capacitor absorbs the steeper power, while the LIB handles the steady power, thereby reducing the power loss of the EV to half. Furthermore, since the in-rush current of the battery is suppressed, there is an improvement in the reliability of the LIB (Noumi et al. 2014). In a hybrid diesel train, 8.2% of the regenerative energy is lost due to batteries’ limited charge-discharge performance; however, using an EDLC with batteries can save this energy ( [[#Takahashi--2017|Takahashi et al. 2017]] ; [[#Mayrink--2020|Mayrink et al. 2020]] ).

The development of power storage devices and advanced integrated system approaches, including power electronics circuits such as HES and their control technologies, are important for the electrification of mobility. These technologies are solutions that could promote the electrification of systems, reduce costs, and contribute to the social environment through multiple outcomes in the decarbonisation agenda.

<div id="10.3.3" class="h2-container"></div>

<span id="fuel-cell-technologies"></span>
=== 10.3.3 Fuel Cell Technologies ===

<div id="h2-11-siblings" class="h2-siblings"></div>

In harder-to-electrify transport segments, such as heavy-duty vehicles, shipping, and aviation, hydrogen holds significant promise for delivering emissions reductions if it is produced using low-carbon energy sources. In particular, hydrogen fuel cells are seen as an emerging option to power larger vehicles for land-based transport ( [[#Tokimatsu--2016|Tokimatsu et al. 2016]] ; [[#IPCC--2018|IPCC 2018]] ; [[#IEA--2019b|IEA 2019b]] ). Despite this potential, further advancements in technological and economic maturity will be required in order for hydrogen fuel cells to play a greater role. While this section focuses primarily on hydrogen fuel cells, ammonia and methanol fuel cells may also emerge as options for low power applications.

During the last decade, hydrogen fuel cell vehicles (HFCVs) have attracted growing attention, with fuel cell technology improving through research and development. Fuel cell systems cost 80% to 95% less than they did in the early 2000s, at approximately USD50 per kW for light-duty (80 kW) and $100 per kW for medium-heavy-duty (160 kW). These costs are approaching the US Department of Energy’s (US DOE) goal of USD40 per kW in 2025 at a production target of 500,000 systems per year ( [[#IEA--2019c|IEA 2019c]] ). In addition to cost reductions, the power density of fuel cell stacks has now reached around 3.0 kilowatt per litre (kW/l) and average durability has improved to approximately 2000 to 3000 hours ( [[#Jouin--2016|Jouin et al. 2016]] ; [[#Kurtz--2019|Kurtz et al. 2019]] ). Despite these improvements, fuel cell systems are not yet mature for many commercial applications. For example, the US DOE has outlined that for hydrogen fuel cell articulated trucks (semi-trailers) to compete with diesel vehicles, fuel cell durability will need to reach 30,000 hours (US DOE 2019). While some fuel cell buses have demonstrated durability close to these targets ( [[#Eudy--2018a|Eudy and Post 2018a]] ), another review of light fuel cell vehicles found maximum durability of 4000 hours ( [[#Kurtz--2019|Kurtz et al. 2019]] ). As more fuel cell vehicles are trialled, it is expected that further real-world data will become available to track ongoing fuel cell durability improvements.

Ammonia and methanol fuel cells are considered to be less mature than hydrogen fuel cells. However, they offer the benefit of using a more easily transported fuel that can be directly used without converting to hydrogen ( [[#Zhao--2019|Zhao et al. 2019]] ). Conversely, both methanol and ammonia are toxic, and in the case of methanol fuel cells, carbon dioxide is released as a by-product of generating electricity with the fuel cell ( [[#Zhao--2019|Zhao et al. 2019]] ). Due to the lower power output, methanol and ammonia fuel cells are also not well suited to heavy-duty vehicles ( [[#Jeerh--2021|Jeerh et al. 2021]] ). They are therefore unlikely to compete with hydrogen fuel cells. However, ammonia and methanol could be converted to hydrogen at refuelling stations as an alternative to being directly used in fuel cells ( [[#Zhao--2019|Zhao et al. 2019]] ).

Several FCV-related technologies are fully ready for demonstration and early market deployment, however, further research and development will be required to achieve full-scale commercialisation, likely from 2030 onwards ( [[#Staffell--2019|Staffell et al. 2019]] ; [[#Energy%20Transitions%20Commission--2020|Energy Transitions Commission 2020]] ; [[#IEA--2021b|IEA 2021b]] ). Some reports argue that it may be possible to achieve serial production of fuel cell heavy-duty trucks in the late 2020s, with comparable costs to diesel vehicles achieved after 2030 ( [[#Jordbakker--2018|Jordbakker et al. 2018]] ). Over the next decade or so, hydrogen FCVs could become cost-competitive for various transport applications, potentially including long-haul trucks, marine ships, and aviation ( [[#Hydrogen%20Council--2017|Hydrogen Council 2017]] ; [[#FCHEA--2019|FCHEA 2019]] ; [[#FCHJU--2019|FCHJU 2019]] ; BloombergNEF 2020; [[#Hydrogen%20Council--2020|Hydrogen Council 2020]] ). The speed of fuel cell system cost reduction is a key factor for achieving widespread uptake. Yet, experts disagree on the relationship between the scale of fuel cell demand, cost, and performance improvements ( [[#Cano--2018|Cano et al. 2018]] ). Costs of light-, medium-, and heavy-duty fuel cell powertrains have decreased by orders of magnitude with further reductions of a factor of two expected with continued technological progress ( [[#Whiston--2019|Whiston et al. 2019]] ). For example, the costs of platinum for fuel cell stacks have decreased by an order of magnitude ( [[#Staffell--2019|Staffell et al. 2019]] ); current generation FCVs use approximately 0.25 g/kW platinum and a further reduction of 50–80% is expected by 2030 ( [[#Hao--2019|Hao et al. 2019]] ).

Hydrogen is likely to take diverse roles in the future energy system: as a fuel in industry and buildings, as well as transport, and as energy storage for variable renewable electricity. Further research is required to understand better how a hydrogen transport fuel supply system fits within the larger hydrogen energy system, especially in terms of integration within existing infrastructure, such as the electricity grid and the natural gas pipeline system ( [[#IEA--2015|IEA 2015]] ).

Strong and durable policies would be needed to enable widespread use of hydrogen as a transport fuel and to sustain momentum during a multi-decade transition period for hydrogen FCVs to become cost-competitive with electric vehicles ( [[#Hydrogen%20Council--2017|Hydrogen Council 2017]] ; [[#FCHEA--2019|FCHEA 2019]] ; [[#FCHJU--2019|FCHJU 2019]] ; [[#IEA--2019c|IEA 2019c]] ; [[#BNEF--2020|BNEF 2020]] ; [[#Hydrogen%20Council--2020|Hydrogen Council 2020]] ). The analysis suggests that hydrogen is likely to have strategic and niche roles in transport, particularly in long-haul shipping and aviation. With continuing improvements, hydrogen and electrification will likely play a role in decarbonising heavy-duty road and rail vehicles.

<div id="10.3.4" class="h2-container"></div>

<span id="refuelling-and-charging-infrastructure"></span>
=== 10.3.4 Refuelling and Charging Infrastructure ===

<div id="h2-12-siblings" class="h2-siblings"></div>

The transport sector relies on liquid gasoline, and diesel for land-based transport, jet fuel for aviation, and heavy fuel oil for shipping. Extensive infrastructure for refuelling liquid fossil fuels already exists. Ammonia, synthetic fuels, and biofuels have emerged as alternative fuels for powering combustion engines and turbines used in land, shipping, and aviation (Figure 10.2). Synthetic fuels such as e-methanol and Fischer-Tropsch liquids have similar physical properties and could be used with existing fossil fuel infrastructure ( [[#Yugo--2019|Yugo and Soler, 2019]] ). Similarly, biofuels have been used in several countries together with fossil fuels ( [[#Panoutsou--2021|Panoutsou et al. 2021]] ). Ammonia is a liquid, but only under pressure, and therefore will not be compatible with liquid fossil fuel refuelling infrastructure. Ammonia is, however, widely used as a fertiliser and chemical raw material and 10% of annual ammonia production is transported via sea ( [[#Gallucci--2021|Gallucci 2021]] ). As such, a number of port facilities include ammonia storage and transport infrastructure and the shipping industry has experience in handling ammonia ( [[#Gallucci--2021|Gallucci 2021]] ). This infrastructure would likely need to be extended in order to support the use of ammonia as a fuel for shipping and therefore ports are likely to be the primary sites for these new refuelling facilities.

EVs and HFCV require separate infrastructure than liquid fuels. The successful diffusion of new vehicle technologies is dependent on the preceding deployment of infrastructure ( [[#Leibowicz--2018|Leibowicz 2018]] ), so that the deployment of new charging and refuelling infrastructure will be critical for supporting the uptake of emerging transport technologies like EVs and HFCVs, where it makes sense for each to be deployed. As a result, there is likely a need for simultaneous investment in both infrastructure and vehicle technologies to accelerate decarbonisation of the transport sector.

'''Charging infrastructure.''' Charging infrastructure is important for a number of key reasons. From a consumer perspective, robust and reliable charging infrastructure networks are required to build confidence in the technology and overcome the often-cited barrier of ‘range anxiety’ ( [[#She--2017|She et al. 2017]] ). Range anxiety is where consumers do not have confidence that an EV will meet their driving range requirements. For LDVs, the majority of charging (75–90%) has been reported to take place at or near homes ( [[#Figenbaum--2017|Figenbaum 2017]] ; [[#Webb--2019|Webb et al. 2019]] ; [[#Wenig--2019|Wenig et al. 2019]] ). Charging at home is a particularly significant factor in the adoption of EVs as consumers are less willing to purchase an EV without home charging ( [[#Berkeley--2017|Berkeley et al. 2017]] ; [[#Funke--2017|Funke and Plötz 2017]] ; [[#Nicholas--2017|Nicholas et al. 2017]] ). However, home charging may not be an option for all consumers. For example, apartment dwellers may face specific challenges in installing charging infrastructure ( [[#Hall--2020|Hall and Lutsey 2020]] ). Thus, the provision of public charging infrastructure is another avenue for alleviating range anxiety, facilitating longer distance travel in EVs, and in turn, encouraging adoption ( [[#Hall--2017|Hall and Lutsey 2017]] ; [[#Melliger--2018|Melliger et al. 2018]] ; [[#Narassimhan--2018|Narassimhan and Johnson 2018]] ; [[#Melton--2020|Melton et al. 2020]] ). Currently, approximately 10% of charging occurs at public locations, roughly split equally between alternating current (AC) (slower) and direct current (DC) (fast) charging ( [[#Figenbaum--2017|Figenbaum 2017]] ; [[#Webb--2019|Webb et al. 2019]] ; [[#Wenig--2019|Wenig et al. 2019]] ). Deploying charging infrastructure at workplaces and commuter car parks is also important, particularly as vehicles are parked at these locations for many hours. Indeed, around 15–30% of EV charging currently occurs at these locations ( [[#Figenbaum--2017|Figenbaum 2017]] ; [[#Webb--2019|Webb et al. 2019]] ; [[#Wenig--2019|Wenig et al. 2019]] ). It has been suggested that automakers and utilities could provide support for the installation of home charging infrastructure ( [[#Hardman--2018|Hardman et al. 2018]] ), while policymakers can provide support for public charging. Such support could come via supportive planning policy, building regulations, and financial support. Policy support could also incentivise the deployment of charging stations at workplaces and commuter car parks. Charging at these locations would have the added benefit of using excess solar energy generated during the day ( [[#Hardman--2018|Hardman et al. 2018]] ; [[#Webb--2019|Webb et al. 2019]] ).

While charging infrastructure is of high importance for the electrification of light-duty vehicles, arguably it is even more important for heavy-duty vehicles, given the costs of high-power charging infrastructure. It is estimated that the installed cost of fast-charging hardware can vary between approximately USD45,000 to USD200,000 per charger, depending on the charging rate, the number of chargers per site, and other site conditions ( [[#Hall--2019|Hall and Lutsey 2019]] ; [[#Nelder--2019|Nelder and Rogers 2019]] ; [[#Nicholas--2019|Nicholas 2019]] ). Deployment of shared charging infrastructure at key transport hubs, such as bus and truck depots, freight distribution centres, marine shipping ports and airports, can encourage a transition to electric vehicles across the heavy transport segments. Furthermore, if charging infrastructure sites are designed to cater for both light- and heavy-duty vehicles, infrastructure costs could decrease by increasing utilisation across multiple applications and/or fleets ( [[#Nelder--2019|Nelder and Rogers 2019]] ).

There are two types of charging infrastructure for electric vehicles: conductive charging involving a physical connection and wireless/induction charging. The majority of charging infrastructure deployed today for light- and heavy-duty vehicles is conductive. However, wireless charging technologies are beginning to emerge – particularly for applications like bus rapid transit – with vehicles able to charge autonomously while parked and/or in motion ( [[#IRENA--2019|IRENA 2019]] ). For road vehicles, electric road systems, or road electrification, is also emerging as an alternative form of conductive charging infrastructure that replaces a physical plug ( [[#Ainalis--2020|Ainalis et al. 2020]] ; [[#Hill--2020|Hill et al. 2020]] ). This type of charging infrastructure is particularly relevant for road freight where load demand is higher. Road electrification can take the form of a charging rail built into the road pavement, run along the side of the road, through overhead catenary power lines – similar to electrical infrastructure used for rail – or at recharging facilities at stations along the route. This infrastructure can also be used to directly power other electrified powertrains, such as hybrid and HFCV ( [[#Hardman--2018|Hardman et al. 2018]] ; [[#Hill--2020|Hill et al. 2020]] ).

Charging infrastructure also varies in terms of the level of charging power. For light vehicles, charging infrastructure is generally up to 350 kW, which provides approximately 350 kilometres for every 10 minutes of charging. For larger vehicles, like buses and trucks, charging infrastructure is generally up to 600 kW, providing around 50–100 km for every 10 minutes of charging (depending on the size of the vehicle). Finally, even higher-power charging infrastructure is currently being developed at rates greater than 1 MW, particularly for long-haul trucks and for short-haul marine shipping and aviation. For example, one of the largest electric ferries in the world, currently operating in Denmark, uses a 4.4 MW charger ( [[#Heinemann--2020|Heinemann et al. 2020]] ).

Finally, there are several different charging standards, varying across transport segments and across geographical locations. Like electrical appliances, different EV charging connectors and sockets have emerged in different regions, such as CCS2 in Europe ( [[#ECA--2021|ECA 2021]] ), GB/T in China ( [[#Hove--2019|Hove and Sandalow 2019]] ). Achieving interoperability between charging stations is seen as another important issue for policymakers to address to provide transparent data to the market on where EV chargers are located and a consistent approach to paying for charging sessions ( [[#van%20der%20Kam--2020|van der Kam and Bekkers 2020]] ). Interoperability could also play an important role in enabling smart charging infrastructure ( [[#Neaimeh--2020|Neaimeh and Andersen 2020]] ).

'''Smart charging: electric vehicle-grid integration strategies.''' EVs provide several opportunities for supporting electricity grids if appropriately integrated. Conversely, a lack of integration could negatively affect the grid, particularly if several vehicles are charged in parallel at higher charging rates during peak demand periods ( [[#Webb--2019|Webb et al. 2019]] ; [[#Jochem--2021|Jochem et al. 2021]] ). There are three primary approaches to EV charging. In unmanaged charging, EVs are charged ad hoc, whenever connected, regardless of conditions on the broader electricity grid ( [[#Webb--2019|Webb et al. 2019]] ; [[#Jochem--2021|Jochem et al. 2021]] ). Second, in managed charging, EVs are charged during periods beneficial to the grid, e.g., at periods of high renewable generation and/or low demand. Managed charging also allows utilities to regulate the rate of charge and can thus provide frequency and regulation services to the grid ( [[#Weis--2014|Weis et al. 2014]] ). Finally, in bidirectional charging or vehicle-to-grid (V2G), EVs are generally subject to managed charging, but an extension provides the ability to export electricity from the vehicle’s battery back to the building and/or wider electricity grid ( [[#Ercan--2016|Ercan et al. 2016]] ; [[#Noel--2019|Noel et al. 2019]] ; [[#Jochem--2021|Jochem et al. 2021]] ). The term ‘smart charging’ has become an umbrella term to encompass both managed charging (often referred to as V1G) and V2G. For electric utilities, smart charging strategies can provide back-up power, support load balancing, reduce peak loads ( [[#Zhuk--2016|Zhuk et al. 2016]] ; [[#Noel--2019|Noel et al. 2019]] ; [[#Jochem--2021|Jochem et al. 2021]] ), reduce the uncertainty in forecasts of daily and hourly electrical loads ( [[#Peng--2012|Peng et al. 2012]] ), and allow greater utilisation of generation capacity ( [[#Hajimiragha--2010|Hajimiragha et al. 2010]] ; [[#Madzharov--2014|Madzharov et al. 2014]] ).

Smart charging strategies can also enhance the climate benefits of EVs ( [[#Yuan--2021|Yuan et al. 2021]] ). Controlled charging can help avoid high-carbon electricity sources, decarbonisation of the ancillary service markets, or peak shaving of high-carbon electricity sources ( [[#Jochem--2021|Jochem et al. 2021]] ). V2G-capable EVs can result in even lower total emissions, particularly when compared to other alternatives ( [[#Reddy--2016|Reddy et al. 2016]] ). [[#Noel--2019|Noel et al. (2019)]] analysed V2G pathways in Denmark and noted that at a penetration rate of 75% by 2030, USD34 billion in social benefits could be accrued (through things like displaced pollution). These social benefits translate to USD1,200 per vehicle. V2G-capable EVs were found to have the potential to reduce carbon emissions compared to a conventional gasoline vehicle by up to 59%, assuming optimised charging schedules ( [[#Hoehne--2016|Hoehne and Chester 2016]] ).

Projections of energy storage suggest smart charging strategies will come to play a significant role in future energy systems. Assessment of different energy storage technologies for Europe showed that V2G offered the most storage potential compared to other options and could account for 200 GW of installed capacity by 2060, whereas utility-scale batteries and pumped hydro storage could provide 160 GW of storage capacity ( [[#Després--2017|Després et al. 2017]] ). Another study found that EVs with controlled charging could provide similar services to stationary storage but at a far lower cost ( [[#Coignard--2018|Coignard et al. 2018]] ). While most deployments of smart charging strategies are still at the pilot stage, the number of projects continues to expand, with the V2G Hub documenting at least 90 V2G projects across 22 countries in 2021 (Vehicle to Grid 2021). Policymakers have an important role in facilitating collaboration between vehicle manufacturers, electricity utilities, infrastructure providers, and consumers to enable smart charging strategies and ensure EVs can support grid stability and the uptake of renewable energy. This is a critical part of decarbonising transport.

'''Hydrogen infrastructure.''' HFCVs are reliant on the development of widespread and convenient hydrogen refuelling stations ( [[#FCHEA--2019|FCHEA 2019]] ; [[#IEA--2019c|IEA 2019c]] ; [[#BNEF--2020|BNEF 2020]] ). Globally, there are around 540 hydrogen refuelling stations, with the majority located in North America, Europe, Japan, and China ( [[#IEA--2021a|IEA 2021a]] ). Approximately 70% of these refuelling stations are open to the public ( [[#Coignard--2018|Coignard et al. 2018]] ). Typical refuelling stations currently have a refuelling capacity of 100 to 350 kg/day ( [[#CARB--2019|CARB 2019]] ; [[#CARB--2020|CARB 2020]] ; [[#H2%20Tools--2020|H2 Tools 2020]] ; [[#AFDC--2021|AFDC 2021]] ). At most, current hydrogen refuelling stations have daily capacities under 500 kg a day ( [[#Liu--2020b|Liu et al. 2020b]] ).

The design of hydrogen refuelling stations depends on the choice of methods for hydrogen supply and delivery, compression and storage, and the dispensing strategy. Hydrogen supply could happen via on-site production or via transport and delivery of hydrogen produced off-site. At the compression stage, hydrogen is compressed to achieve the pressure needed for economic stationary and vehicle storage. This pressure depends on the storage strategy. Hydrogen can be stored as a liquid or a gas. Hydrogen can also be dispensed to vehicles as a gas or a liquid, depending on the design of the vehicles (though it tests the extremes of temperature range and storage capacity for an industrial product). The technological and economic development of each of these components continues to be researched.

If hydrogen is produced off site in a large centralised plant, it must be stored and delivered to refuelling stations. The cost of hydrogen delivery depends on the amount of hydrogen delivered, the delivery distance, the storage method (compressed gas or cryogenic liquid), and the delivery mode (truck or pipeline). Table 10.6 describes the three primary options for hydrogen delivery. Most hydrogen refuelling stations today are supplied by trucks and, very occasionally, hydrogen pipelines. Gaseous tube trailers could also be used to deliver hydrogen in the near term, or over shorter distances, due to the low fixed cost (although the variable cost is high). Both liquefied truck trailers and pipelines are recognised as options in the medium to long term as they have higher capacities and lower costs over longer distances ( [[#FCHJU--2019|FCHJU 2019]] ; [[#Li--2020|Li et al. 2020]] ; [[#EU--2021|EU 2021]] ). Alternatively, hydrogen can be produced on site using a small-scale on-site electrolyser or steam methane reforming unit combined with CCS. Hydrogen is generally dispensed to vehicles as a compressed gas at pressures 350 or 700 bar, or as liquified hydrogen at –253°C ( [[#Hydrogen%20Council--2020|Hydrogen Council 2020]] ).

'''Table 10.6 | Overview of three transport technologies for hydrogen delivery in the transport sector showing relative differences.''' Source: [[#IEA--2019c|IEA (2019c)]] .

{| class="wikitable"
|-
|
| '''Capacity'''

| '''Delivery distance'''

| '''Energy loss'''

| '''Fixed costs'''

| '''Variable costs'''

| '''Deployment phase'''

|-
| Gaseous tube trailers

| Low

| Low

| Low

| Low

| High

| Near term

|-
| Liquefied truck trailers

| Medium

| High

| High

| Medium

| Medium

| Medium to long term

|-
| Hydrogen pipelines

| High

| High

| Low

| High

| Low

| Medium to long term

|}

The costs for hydrogen refuelling stations vary widely and remain uncertain for the future ( [[#IEA--2019c|IEA 2019c]] ). The IEA reports that the investment cost for one hydrogen refuelling station ranges between USD0.6 million and USD2 million for hydrogen at a pressure of 700 bar and a delivery capacity of 1300 kg per day. The investment cost of hydrogen refuelling stations with lower refuelling capacities (~50 kg H 2 per day) delivered at lower pressure (350 bar) range between USD0.15–1.6 million. A separate estimate by the International Council for Clean Transport suggests that at a capacity of 600 kg of hydrogen per day, the capital cost of a single refuelling station would be approximately USD1.8 million ( [[#ICCT--2017|ICCT 2017]] ). Given the high investment costs for hydrogen refuelling stations, low utilisation can translate into a high price for delivered hydrogen. In Europe, most pumps operate at less than 10% capacity. For small refuelling stations with a capacity of 50 kg H 2 per day, this utilisation rate translates to a high price of around USD15–25 per kg H 2 – in line with current retail prices ( [[#IEA--2019c|IEA 2019c]] ). The dispensed cost of hydrogen is also highly correlated with the cost of electricity, when H 2 is produced using electrolysis, which is required to produce low-carbon hydrogen.

<div id="10.4" class="h1-container"></div>

<span id="decarbonisation-of-land-based-transport"></span>