Editing IPCC:AR6/WGIII/Chapter-6 (section)

== 6.6 Key Characteristics of Net-zero Energy Systems ==

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=== 6.6.1 What is a Net-zero Energy System? ===

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Limiting warming to well below 2°C requires that CO 2 emissions from the energy sector be reduced to near zero or even below zero ( [[#6.7|Section 6.7]] ; Chapter 3). Policies, technologies, behaviours, investments, and other factors will determine the speed at which countries transition to net-zero energy systems – those that emit very little or no emissions. An understanding of these future energy systems can help to chart a course toward them over the coming decades.

This section synthesises current understanding of net-zero energy systems. Discussions surrounding efforts to limit warming are frequently communicated in terms of the point in time at which net anthropogenic CO 2 emissions reach zero, accompanied by substantial reductions in non-CO 2 emissions ( [[#IPCC--2018|IPCC 2018]] , Chapter 3). Net-zero GHG goals are also common, and they require net-negative CO 2 emissions to compensate for residual non-CO 2 emissions. Economy-wide CO 2 and GHG goals appear in many government and corporate decarbonisation strategies, and they are used in a variety of ways. Most existing carbon-neutrality commitments from countries and sub-national jurisdictions aim for economies with very low emissions rather than zero emissions. Offsets, carbon dioxide removal (CDR) methods, and/or land sink assumptions are used to achieve net-zero goals (Kelly [[#Levin--2020|Levin et al. 2020]] ).

Precisely describing a net-zero energy system is complicated by the fact that different scenarios attribute different future CO 2 emissions to the energy system, even under scenarios where economy-wide CO 2 emissions reach net zero. It is also complicated by the dependence of energy system configurations on unknown future conditions such as population and economic growth, and technological change. The energy system is not the only source or sink of CO 2 emissions. Terrestrial systems may store or emit carbon, and CDR options like BECCS or DACCS can be used to store CO 2 , relieving pressure on the energy system (Chapter 3). The location of such CDR options is ambiguous, as it might be deployed within or outside of the energy sector (Figure 6.21), and many CDR options, such as DACCS, would be important energy consumers ( [[#Bistline--2021a|Bistline and Blanford 2021a]] ) ( [[#6.6.2|Section 6.6.2]] ). If CDR methods are deployed outside of the energy system (e.g., net negative agriculture, forestry, and land-use CO 2 emissions), it is possible for the energy system to still emit CO 2 but have economy-wide emissions of zero or below. When global energy and industrial CO 2 emissions reach net zero, the space remaining for fossil energy emissions is determined by deployment of CDR options (Figure 6.21).

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[[File:89b04fcd109c67b725a4855034146497 IPCC_AR6_WGIII_Figure_6_21.png]]

'''Figure 6.21 | Residual emissions and carbon dioxide removal (CDR) when global energy and industrial CO''' 2 '''emissions reach net-zero.''' Residual emissions and CDR in net-zero scenarios from the AR6 Scenarios Database show global differences across warming levels (light blue = scenarios that limit warming to 1.5°C (&gt;50%) with no or limited overshoot and scenarios that return warming to 1.5°C (&gt;50%) after a high overshoot; yellow = scenarios that limit warming to 2°C (&gt;67%) and scenarios that limit warming to 2°C (&gt;50%); dark blue = scenarios that limit warming to 2.5°C (&gt;50%), scenarios that limit warming to 3°C (&gt;50%), scenarios that limit warming to 4°C (&gt;50%), and scenarios that exceed warming of 4°C (≥50%)). In each case, the boxes show the 25th to 75th percentile ranges, and whiskers show the 5th and 95th percentiles. Lines and circles within the boxes denote the median and mean values, respectively.

This section focuses on energy systems that produce very little or no CO 2 emissions, referred to in this chapter as ‘net-zero energy systems’. While energy systems may not reach net zero concurrently with economy-wide CO 2 or GHG emissions, they are a useful benchmark for planning a path to net zero. Note that the focus here is on energy systems with net-zero CO 2 emissions from fossil fuel combustion and industrial processes, but the lessons will be broadly applicable to net-zero GHG energy systems as well. Net-zero GHG energy systems would incorporate the major efforts made to reduce non-CO 2 emissions (e.g., CH 4 from oil, gas and coal as discussed in [[#6.4|Section 6.4]] ) and would also need to incorporate more CDR to compensate for remaining non-CO 2 GHG emissions. Energy sector emissions in many countries may not reach net zero at the same time as global energy system emissions (Figure 6.25 and Cross-Chapter Box 3 in Chapter 3).

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=== 6.6.2 Configurations of Net-zero Energy Systems ===

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Net-zero energy systems entail trade-offs across economic, environmental, and social dimensions ( [[#Davis--2018|Davis et al. 2018]] ). Many socio-economic, policy, and market uncertainties will also influence the configuration of net-zero energy systems ( [[#Smith--2015|Smith et al. 2015]] ; [[#van%20Vuuren--2018|van Vuuren et al. 2018]] ; [[#Bistline--2019|Bistline et al. 2019]] ; [[#Krey--2019|Krey et al. 2019]] ; [[#Azevedo--2021|Azevedo et al. 2021]] , [[#Pye--2021|Pye et al. 2021]] ). There are reasons that countries might focus on one system configuration versus another, including cost, resource endowments, related industrial bases, existing infrastructure, geography, governance, public acceptance, and other policy priorities ( [[#6.6.4|Section 6.6.4]] and Chapter 18 of WGII).

Explorations of net-zero energy systems have been emerging in the detailed systems modelling literature ( [[#Azevedo--2021|Azevedo et al. 2021]] ; [[#Bistline--2021b|Bistline 2021b]] ). Reports associated with net-zero economy-wide targets for countries and sub-national entities typically do not provide detailed roadmaps or modelling but discuss high-level guiding principles, though more detailed studies are emerging at national levels ( [[#Capros--2019|Capros et al. 2019]] ; [[#Wei--2020|Wei et al. 2020]] ; [[#Duan--2021|Duan et al. 2021]] ; [[#Williams--2021a|Williams et al. 2021a]] ). Most analysis has focused on identifying potential decarbonisation technologies and pathways for different sectors, enumerating opportunities and barriers for each, their costs, highlighting robust insights, and characterising key uncertainties ( [[#Davis--2018|Davis et al. 2018]] ; [[#Hepburn--2019|Hepburn et al. 2019]] ).

The literature on the configuration of net-zero energy systems is limited in a few respects. On the one hand, there is a robust integrated assessment literature that provides characterisations of these systems in broad strokes (the AR6 database), offering internally consistent global scenarios to link global warming targets to regional/national goals. All integrated assessment scenarios that discuss net-zero energy system CO 2 emissions provide high-level characterisations of net-zero systems. Because these characterisations have less temporal, spatial, technological, regulatory, and societal detail, however, they may not consider the complexities that could ultimately influence regional, national, or local pathways. High-fidelity models and analyses are needed to assess the economic and environmental characteristics and the feasibility of many aspects of net-zero or net-negative emissions energy systems ( ''high confidence'' ) ( [[#Blanford--2018|Blanford et al. 2018]] ; [[#Bistline--2020|Bistline and Blanford 2020]] ). For example, evaluating the competitiveness of electricity sector technologies requires temporal, spatial, and technological detail to accurately represent system investments and operations ( [[#Collins--2017|Collins et al. 2017]] ; [[#Santen--2017|Santen et al. 2017]] ; Helistoe et al. 2019; [[#Bistline--2021c|Bistline 2021c]] ; [[#Victoria--2021|Victoria et al. 2021]] ).

Configurations of net-zero energy systems will vary by region but are likely to share several common characteristics ( ''high confidence'' ) (Figure 6.22). We focus on seven of those common characteristics in the remainder of this subsection.

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[[File:b4f15a3c586b00584ada54b2cfbb6621 IPCC_AR6_WGIII_Figure_6_22.png]]

'''Figure 6.22 | Characteristics of global net-zero energy systems when global energy and industrial CO''' 2 '''emissions reach net-zero.'''

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==== 6.6.2.1 Limited and/or Targeted Use of Fossil Fuels ====

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Net-zero energy systems will use far less fossil fuel than today ( ''high confidence'' ). The precise quantity of fossil fuels will largely depend on the relative costs of such fuels, electrification, alternative fuels, and CDR ( [[#6.6.2.4|Section 6.6.2.4]] ) in the energy system ( ''high confidence'' ). All of these are affected by regional differences in resources ( [[#McGlade--2015|McGlade and Ekins 2015]] ), existing energy infrastructure ( [[#Tong--2019|Tong et al. 2019]] ), demand for energy services, and climate and energy policies. Fossil fuel use may persist, for example, if and where the costs of such fuels and the compensating carbon management (e.g., CDR, CCS) are less than non-fossil energy. For most applications, however, it is likely that electrification ( [[#McCollum--2014|McCollum et al. 2014]] ; [[#Madeddu--2020|Madeddu et al. 2020]] ; [[#Zhang--2020|Zhang and Fujimori 2020]] ) or use of non-fossil alternative fuels ( [[#Zeman--2008|Zeman and Keith 2008]] ; [[#Graves--2011|Graves et al. 2011]] ; [[#Hänggi--2019|Hänggi et al. 2019]] ; [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ) will prove to be the cheapest options. Most residual demand for fossil fuels is likely to predominantly be petroleum and natural gas given their high energy density ( [[#Davis--2018|Davis et al. 2018]] ), while demand for coal in net-zero energy systems is likely to be very low ( [[#Luderer--2018|Luderer et al. 2018]] ; [[#Jakob--2020|Jakob et al. 2020]] , [[#6.7.4|Section 6.7.4]] ) ( ''high confidence'' ).

There is considerable flexibility regarding the overall quantity of liquid and gaseous fuels that will be required in net-zero energy systems ( ''high confidence'' ) (Figure 6.22 and [[#6.7.4|Section 6.7.4]] ). This will be determined by the relative value of such fuels as compared to systems which rely more or less heavily on zero-emissions electricity. In turn, the share of any fuels that are fossil or fossil-derived is uncertain and will depend on the feasibility of CCS and CDR technologies and long-term sequestration as compared to alternative, carbon-neutral fuels. Moreover, to the extent that physical, biological, and/or socio-political factors limit the availability of CDR ( [[#Smith--2015|Smith et al. 2015]] ; [[#Field--2017|Field and Mach 2017]] ), carbon management efforts may prioritise residual emissions related to land use and other non-energy sources.

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==== 6.6.2.2 Zero or Negative CO 2 Emissions from Electricity ====

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Net-zero energy systems will rely on decarbonised or net-negative CO 2 emissions electricity systems, due to the many lower-cost options for producing zero-carbon electricity and the important role of end-use electrification in decarbonising other sectors ( ''high confidence'' ).

There are many possible configurations and technologies for zero- or net-negative-emissions electricity systems ( ''high confidence'' ). These systems could entail a mix of variable renewables, dispatchable renewables (e.g., biomass, hydropower), other firm, dispatchable (‘on-demand’) low-carbon generation (e.g., nuclear, CCS-equipped capacity), energy storage, transmission, carbon removal options (e.g., BECCS, DACCS), and demand management ( [[#Luderer--2017|Luderer et al. 2017]] ; [[#Bistline--2018|Bistline et al. 2018]] ; [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Bistline--2021b|Bistline and Blanford 2021b]] ). The marginal cost of deploying electricity sector mitigation options increases as electricity emissions approach zero; in addition, the most cost-effective mix of system resources changes as emissions approach zero and, therefore, so do the implications of electricity sector mitigation for sustainability and other societal goals ( [[#Mileva--2016|Mileva et al. 2016]] ; [[#Bistline--2018|Bistline et al. 2018]] ; [[#Sepulveda--2018|Sepulveda et al. 2018]] ; [[#Jayadev--2020|Jayadev et al. 2020]] ; [[#Cole--2021|Cole et al. 2021]] ). Key factors influencing the electricity mix include relative costs and system benefits, local resource bases, infrastructure availability, regional integration and trade, co-benefits, societal preferences and other policy priorities, all of which vary by country and region ( [[#6.6.4|Section 6.6.4]] ). Many of these factors depend on when the net-zero point is reached (Figure 6.22).

Based on their increasing economic competitiveness, VRE technologies, especially wind and solar power, will likely comprise large shares of many regional generation mixes ( ''high confidence'' ) (Figure 6.22). While wind and solar will likely be prominent electricity resources, this does not imply that 100% renewable energy systems will be pursued under all circumstances, since economic and operational challenges increase nonlinearly as shares approach 100% (Box 6.8) ( [[#Frew--2016|Frew et al. 2016]] ; [[#Imelda--2018|Imelda et al. 2018]] b; [[#Shaner--2018|Shaner et al. 2018]] ; [[#Bistline--2021a|Bistline and Blanford 2021a]] ; [[#Cole--2021|Cole et al. 2021]] ). Real-world experience planning and operating regional electricity systems with high instantaneous and annual shares of renewable generation is accumulating, but debates continue about how much wind and solar should be included in different systems, and the cost-effectiveness of mechanisms for managing variability (Box 6.8). Either firm, dispatchable generation (including nuclear, CCS-equipped capacity, dispatchable renewables such as geothermal, and fossil units run with low capacity factors and CDR to balance emissions) or seasonal energy storage (alongside other balancing resources discussed in Box 6.8) will be needed to ensure reliability and resource adequacy with high percentages of wind and solar ( [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Dowling--2020|Dowling et al. 2020]] ; [[#Denholm--2021|Denholm et al. 2021]] ) though each option involves uncertainty about costs, timing, and public acceptance ( [[#Albertus--2020|Albertus et al. 2020]] ).

Electricity systems require a range of different functional roles – for example, providing energy, capacity, or ancillary services. As a result, a range of different types of generation, energy storage, and transmission resources may be deployed in these systems ( [[#Baik--2021|Baik et al. 2021]] ). There are many options for each of these roles, each with their strengths and weaknesses (Sections 6.4.3 and 6.4.4), and deployment of these options will be influenced by the evolution of technological costs, system benefits, and local resources ( [[#Fell--2013|Fell and Linn 2013]] ; [[#Hirth--2015|Hirth 2015]] ; [[#Bistline--2018|Bistline et al. 2018]] ; [[#Mai--2018|Mai et al. 2018]] ; [[#Veers--2019|Veers et al. 2019]] ).

System management is critical for zero- or negative-emissions electricity systems. Maintaining reliability will increasingly entail system planning and operations that account for characteristics of supply- and demand-side resources ( [[#Hu--2018|Hu et al. 2018]] ). Coordinated planning and operations will likely become more prevalent across portions of the electricity system (e.g., integrated generation, transmission, and distribution planning), across sectors, and across geographies ( [[#EPRI--2017|EPRI 2017]] ; [[#Konstantelos--2017|Konstantelos et al. 2017]] ; [[#Chan--2018|Chan et al. 2018]] ; [[#Bistline--2019|Bistline and Young 2019]] ) ( [[#6.4.3|Section 6.4.3]] ).

Energy storage will be increasingly important in net-zero energy systems, especially in systems with shares of VRE ( ''high confidence'' ). Deployment of energy storage will vary based on the system benefits and values of different options ( [[#Arbabzadeh--2019|Arbabzadeh et al. 2019]] ; [[#Denholm--2019|Denholm and Mai 2019]] ). Diurnal storage options like lithium-ion batteries have different value than storing and discharging electricity over longer periods through long-duration energy storage with less frequent cycling, which require different technologies, supporting policies, and business models ( [[#Gallo--2016|Gallo et al. 2016]] ; Blanco and Faaij 2017; [[#Albertus--2020|Albertus et al. 2020]] ; [[#Dowling--2020|Dowling et al. 2020]] ; [[#Sepulveda--2021|Sepulveda et al. 2021]] ) ( [[#6.4.4|Section 6.4.4]] ). The value of energy storage varies with the level of deployment and on the competitiveness of economic complements such as VRE options ( [[#Mileva--2016|Mileva et al. 2016]] ; [[#Bistline--2020|Bistline and Young 2020]] ) and substitutes such as flexible demand ( [[#Brown--2018|Brown et al. 2018]] ; [[#Merrick--2018|Merrick et al. 2018]] ), transmission ( [[#Schlachtberger--2017|Schlachtberger et al. 2017]] ; [[#Brown--2018|Brown et al. 2018]] ; [[#Merrick--2018|Merrick et al. 2018]] ; [[#Bistline--2019|Bistline and Young 2019]] ), trade ( [[#Bistline--2020b|Bistline et al. 2020b]] ), dispatchable generators ( [[#Hittinger--2015|Hittinger and Lueken 2015]] ; [[#Gils--2017|Gils et al. 2017]] ; [[#Arbabzadeh--2019|Arbabzadeh et al. 2019]] ), direct air capture (DAC) ( [[#Daggash--2019|Daggash et al. 2019]] ), and efficiencies in system operations (Tuohy et al. 2015).

The approach to other sectors could impact on electricity sector planning, and the role of some technologies (e.g., hydrogen, batteries, CCS) could depend on deployment in other sectors. CCS offers opportunities for CO 2 removal when fuelled with syngas or biomass containing carbon captured from the atmosphere ( [[#Hepburn--2019|Hepburn et al. 2019]] ); however, concerns about lifecycle environmental impacts, uncertain costs, and public acceptance are potential barriers to widespread deployment ( [[#6.4.2|Section 6.4.2]] ). It is unclear whether CDR options like BECCS will be included in the electricity mix to offset continued emissions in other parts of the energy system or beyond (MacDowell et al. 2017; [[#Bauer--2018|Bauer et al. 2018]] a; [[#Luderer--2018|Luderer et al. 2018]] ). Some applications may also rely on power to fuels (PtX) electricity conversion to create low-emissions synthetic fuels (Sections 6.6.2.6, 6.4.4, and 6.4.5), which could impact on electricity system planning and operations. Additionally, if DAC technologies are used, electricity and heat requirements to operate DAC could impact electricity system investments and operations ( [[#Realmonte--2019|Realmonte et al. 2019]] ; [[#Bistline--2021a|Bistline and Blanford 2021a]] ).

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=== Box 6.8 | 100% Renewables in Net-zeroEnergy Systems ===

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The decreasing cost and increasing performance of renewable energy has generated interest in the feasibility of providing nearly all energy services with renewables. Renewable energy includes wind power, solar power, hydroelectric power, bioenergy, geothermal energy, tidal power, and ocean power. There are two primary frames around which 100% renewable energy systems are discussed: 100% renewable electricity systems and 100% renewable energy systems, considering not only electricity but all aspects of the energy system.

It is technically feasible to use very high renewable shares (e.g., above 75% of annual regional generation) to meet hourly electricity demand under a range of conditions, especially when VRE options, notably wind and solar, are complemented by other resources ( ''high confidence'' ). There are currently many grids with high renewable shares and large anticipated roles for VRE sources, in particular wind and solar ( [[#6.4|Section 6.4]] ), in future low-carbon electricity systems. An increasingly large set of studies examines the feasibility of high renewable penetration and economic drivers under different policy, technology, and market scenarios ( [[#Cochran--2014|Cochran et al. 2014]] ; [[#Deason--2018|Deason 2018]] ; [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Bistline--2019|Bistline et al. 2019]] ; [[#Hansen--2019|Hansen et al. 2019]] ; [[#Dowling--2020|Dowling et al. 2020]] ; [[#Blanford--2021|Blanford et al. 2021]] ; [[#Denholm--2021|Denholm et al. 2021]] ). High wind and solar penetration involves technical and economic challenges due to their unique characteristics such as spatial and temporal variability, short- and long-term uncertainty, and non-synchronous generation ( [[#Cole--2017|Cole et al. 2017]] ). These challenges become increasingly important as renewable shares approach 100% (Sections 6.6.2.2 and 6.4.3).

There are many balancing options in systems with very high renewables ( [[#Milligan--2015|Milligan et al. 2015]] ; [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Mai--2018|Mai et al. 2018]] ; [[#Bistline--2021a|Bistline 2021a]] ; [[#Denholm--2021|Denholm et al. 2021]] ).

'''•''' '''Energy storage.''' Energy storage technologies like batteries, pumped hydro, and hydrogen can provide a range of system services ( [[#Balducci--2018|Balducci et al. 2018]] ; [[#Bistline--2020a|Bistline et al. 2020a]] ) ( [[#6.4.4|Section 6.4.4]] ). Lithium-ion batteries have received attention as costs fall and installations increase, but very high renewable shares typically entail either dispatchable generation or long-duration storage in addition to short-duration options ( [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Arbabzadeh--2019|Arbabzadeh et al. 2019]] ; [[#Schill--2020|Schill 2020]] ). Energy storage technologies are part of a broad set of options (including synchronous condensers, demand-side measures, and even inverter-based technologies themselves) for providing grid services ( [[#Castillo--2014|Castillo and Gayme 2014]] ; [[#EPRI--2019a|EPRI 2019a]] ).

'''•''' '''Transmission and trade.''' To balance differences in resource availability, high renewable systems will very likely entail investments in transmission capacity ( [[#Mai--2014|Mai et al. 2014]] ; Macdonald et al. 2016; [[#Pleßmann--2017|Pleßmann and Blechinger 2017]] ; [[#Zappa--2019|Zappa et al. 2019]] ) ( [[#6.4.5|Section 6.4.5]] ) and changes in trade ( [[#Abrell--2016|Abrell and Rausch 2016]] ; [[#Bistline--2019|Bistline et al. 2019]] ). These increases will likely be accompanied by expanded balancing regions to take advantage of geographical smoothing.

'''•''' '''Dispatchable (‘on-demand’) generation.''' Dispatchable generation could include flexible fossil units or low-carbon fuels such as hydrogen with lower minimum load levels ( [[#Denholm--2018|Denholm et al. 2018]] ; [[#Bistline--2019|Bistline 2019]] ), renewables like hydropower, geothermal, or biomass ( [[#Hirth--2016|Hirth 2016]] ; [[#Hansen--2019|Hansen et al. 2019]] ), or flexible nuclear ( [[#Jenkins--2018a|Jenkins et al. 2018a]] ). The composition depends on costs and other policy goals, though in all cases, capacity factors are low for these resources ( [[#Mills--2020|Mills et al. 2020]] ).

'''•''' '''Demand management:''' Many low-emitting and high-renewables systems also utilise increased load flexibility in the forms of energy efficiency, demand response, and demand flexibility, utilising newly electrified end uses such as electric vehicles to shape demand profiles to better match supply ( [[#Ameli--2017|Ameli et al. 2017]] ; Hale 2017; [[#Brown--2018|Brown et al. 2018]] ; [[#Imelda--2018|Imelda et al. 2018]] a; [[#Bistline--2021a|Bistline 2021a]] ).

'''•''' '''Sector coupling:''' Sector coupling includes increased end-use electrification and PtX electricity conversion pathways, which may entail using electricity to create synthetic fuels such as hydrogen ( [[#Davis--2018|Davis et al. 2018]] ; [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ) (Sections 6.4.3, 6.4., 6.4.5, 6.6.4.3, and 6.6.4.6).

Deployment of integration options depends on their relative costs and value, regulations, and electricity market design. There is considerable uncertainty about future technology costs, performance, availability, scalability, and public acceptance ( [[#Kondziella--2016|Kondziella and Bruckner 2016]] ; [[#Bistline--2019|Bistline et al. 2019]] ). Deploying balanced resources likely requires operational, market design, and other institutional changes, as well as technological changes in some cases ( [[#Denholm--2021|Denholm et al. 2021]] ; [[#Cochran--2014|Cochran et al. 2014]] ). Mixes will differ based on resources, system size, flexibility, and whether grids are isolated or interconnected.

Box 6.8

Although there are no technical upper bounds on renewable electricity penetration, the economic value of additional wind and solar capacity typically decreases as their penetration rises, creating economic challenges at higher deployment levels ( [[#Hirth--2013|Hirth 2013]] ; [[#Gowrisankaran--2016|Gowrisankaran et al. 2016]] ; [[#Cole--2021|Cole et al. 2021]] ; [[#Denholm--2021|Denholm et al. 2021]] ; [[#Millstein--2021|Millstein et al. 2021]] ). The integration options above, as well as changes to market design, can mitigate these challenges but likely will not solve them, especially since these options can exhibit declining value themselves (De Sisternes et al. 2016; [[#Bistline--2017|Bistline 2017]] ; [[#Denholm--2019|Denholm and Mai 2019]] ) and may be complements or substitutes to each other.

Energy systems that are 100% renewable (including all parts of the energy sector, and not only electricity generation) raise a range of technological, regulatory, market, and operational challenges that make their competitiveness uncertain ( ''high confidence'' ). These systems require decarbonising all electricity, using this zero-carbon electricity broadly, and then utilising zero-carbon energy carriers for all end uses not served by electricity, for example, air travel, long-distance transport, and high-temperature process heat. Broader questions emerge regarding the attractiveness of supplying all energy, and not just electricity, with renewables (Figure 6.22). Integrated assessment and energy systems research suggest large roles for renewables, but energy and electricity shares are far from 100%, even with stringent emissions reductions targets and optimistic assumptions about future cost reductions ( [[#Bauer--2018|Bauer et al. 2018]] ; [[#Bistline--2018|Bistline et al. 2018]] ; [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Huntington--2020|Huntington et al. 2020]] ) ( [[#6.7.1|Section 6.7.1]] ). Scenarios with 100% renewable energy systems are an emerging subset in the decarbonisation literature, especially at regional levels ( [[#Hansen--2019|Hansen et al. 2019]] ; [[#Denholm--2021|Denholm et al. 2021]] ). Many 100% renewables studies focus more heavily on electrification for decarbonising end uses, and include less biofuels and hydrogen than the broader literature on deep decarbonisation ( [[#Bauer--2018|Bauer et al. 2018]] a). These studies typically assume a constrained set of available technologies to demonstrate the technical feasibility of very high renewable systems and do not optimise to find least-cost, technology-neutral decarbonisation pathways, and many 100% renewables studies focus on the electricity sector or a limited number of sectors ( [[#Jenkins--2018a|Jenkins et al. 2018a]] ; [[#Hansen--2019|Hansen et al. 2019]] ). In addition to renewables, studies broadly agree that including additional low-carbon options – including not only low-carbon electricity but also targeted use of fossil fuels with and without CCS ( [[#6.6.2.1|Section 6.6.2.1]] ) and alternative fuels for sectors that are difficult to electrify ( [[#6.6.2.4|Section 6.6.2.4]] ) – can lower the cost of decarbonisation, even with very high shares of renewables (Figure 6.22). However, there is disagreement about the magnitude of cost savings from larger portfolios, which depend on context- and scenario-specific assumptions about technologies, markets, and policies.

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==== 6.6.2.3 Widespread Electrification of End Uses ====

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Net-zero energy systems will rely more heavily on increased use of electricity (electrification) in end uses ( ''high confidence'' ). The literature on net-zero energy systems almost universally calls for increased electrification ( [[#Sugiyama--2012|Sugiyama 2012]] ; [[#Williams--2012|Williams et al. 2012]] ; [[#Kriegler--2014a|Kriegler et al. 2014a]] ; [[#Williams--2014|Williams et al. 2014]] ; [[#Rogelj--2015a|Rogelj et al. 2015a]] ; [[#Sachs--2016|Sachs et al. 2016]] ; [[#Luderer--2018|Luderer et al. 2018]] ; [[#Sven--2018|Sven et al. 2018]] ; [[#Schreyer--2020|Schreyer et al. 2020]] ). At least 30% of the global final energy needs are expected to be served by electricity, with some estimates suggesting upwards of 80% of total energy use being electrified (Figure 6.22, panel c). Increased electrification is especially valuable in net-zero energy systems in tandem with decarbonised electricity generation or net-negative emissions electricity generation ( [[#6.5.4|Section 6.5.4]] .2). Flexible electric loads (electric vehicles, smart appliances) can in turn facilitate incorporation of VRE electricity options, increase system flexibility, and reduce needs for grid storage ( [[#6.4.3|Section 6.4.3]] ) ( [[#Mathiesen--2015|Mathiesen et al. 2015]] ; Lund et al. 2018).

Several end uses, such as passenger transportation (light-duty electric vehicles, two and three wheelers, buses, rail) as well as building energy uses (lighting, cooling) are likely to be electrified in net-zero energy systems ( ''high confidence'' ). Variations in projections of electrification largely result from differences in expectations about the ability and cost-competitiveness of electricity to serve other end uses such as non-rail freight transport, aviation, and heavy industry ( [[#McCollum--2014|McCollum et al. 2014]] ; [[#Bataille--2016|Bataille et al. 2016]] ; [[#EPRI--2018|EPRI 2018]] ; [[#Breyer--2019|Breyer et al. 2019]] ) ( [[#6.5.4|Section 6.5.4]] .4), especially relative to biofuels and hydrogen (‘low-carbon fuels’) ( [[#McCollum--2014|McCollum et al. 2014]] ; [[#Sachs--2016|Sachs et al. 2016]] ; [[#Rockström--2017|Rockström et al. 2017]] ), the prospects for which are still quite uncertain ( [[#6.4|Section 6.4]] ). The emergence of CDR technologies and the extent to which they allow for residual emissions as an alternative to electrification will also affect the overall share of energy served by electricity ( [[#6.6.2.7|Section 6.6.2.7]] ).

Regions endowed with cheap and plentiful low-carbon electricity resources (wind, solar, hydropower) are likely to emphasise electrification, while those with substantial bioenergy resources or availability of other liquid fuels might put less emphasis on electrification, particularly in hard-to-electrify end uses ( ''medium confidence'' ). For example, among a group of Latin American countries, relative assumptions about liquid fuels and electricity result in an electrification range of 28–82% for achieving a net-zero energy system ( [[#Bataille--2020|Bataille et al. 2020]] ). Similarly, the level of penetration of biofuels that can substitute for electrification will depend on regional circumstances such as land-use constraints, competition with food, and sustainability of biomass production ( [[#6.6.2.4|Section 6.6.2.4]] ).

Electrification of most buildings services, with the possible exception of space heating in extreme climates, is expected in net-zero energy systems ( ''high confidence'' ) (Chapter 9). Space cooling and water heating are expected to be largely electrified. Building electrification is expected to rely substantially on heat pumps, which will help lower emissions both through reduced thermal requirements and higher efficiencies ( [[#Mathiesen--2015|Mathiesen et al. 2015]] ; [[#Sven--2018|Sven et al. 2018]] ; [[#Rissman--2020|Rissman et al. 2020]] ). The level of electrification for heating will depend on the trade-offs between building or household level heat pumps versus more centralised district heating network options ( [[#Mathiesen--2015|Mathiesen et al. 2015]] ; [[#Brown--2018|Brown et al. 2018]] ), as well as the cost and performance of heat pumps in more extreme climates and regional grid infrastructure ( [[#EPRI--2018|EPRI 2018]] ; [[#Waite--2020|Waite and Modi 2020]] ).

A significant share of transportation, especially road transportation, is expected to be electrified in net-zero energy systems ( ''high confidence'' ). In road transportation, two- and three-wheelers, light-duty vehicles (LDVs), and buses, are especially amenable to electrification, with more than half of passenger LDVs expected to be electrified globally in net-zero energy systems ( ''medium confidence'' ) ( [[#Fulton--2015|Fulton et al. 2015]] ; [[#Sven--2018|Sven et al. 2018]] ; [[#Khalili--2019|Khalili et al. 2019]] ; [[#Bataille--2020|Bataille et al. 2020]] ). Long-haul trucks, large ships, and aircraft are expected to be harder to electrify without technological breakthroughs ( [[#Fulton--2015|Fulton et al. 2015]] ; [[#Mathiesen--2015|Mathiesen et al. 2015]] ), although continued improvements in battery technology may enable electrification of long-haul trucks ( [[#Nykvist--2021|Nykvist and Olsson 2021]] ) (Chapter 10). Due to the relative ease of rail electrification, near complete electrification of rail and a shift of air and truck freight to rail is expected in net-zero energy systems ( [[#Fulton--2015|Fulton et al. 2015]] ; [[#Rockström--2017|Rockström et al. 2017]] ; [[#Sven--2018|Sven et al. 2018]] ; [[#Khalili--2019|Khalili et al. 2019]] ). The degree of modal shifts and electrification will depend on local factors such as infrastructure availability and location accessibility. Due to the challenges associated with electrification of some transport modes, net-zero energy systems may include some residual emissions associated with the freight sector that are offset through CDR technologies ( [[#Muratori--2017b|Muratori et al. 2017b]] ), or reliance on low and zero-carbon fuels instead of electrification.

A non-trivial number of industry applications could be electrified as a part of a net-zero energy system, but direct electrification of heavy industry applications such as cement, primary steel manufacturing, and chemical feedstocks is expected to be challenging ( ''medium confidence'' ) ( [[#Davis--2018|Davis et al. 2018]] ; [[#Philibert--2019|Philibert 2019]] ; [[#Madeddu--2020|Madeddu et al. 2020]] ; van Sluisveld et al. 2021). Process and boiler heating in industrial facilities are anticipated to be electrified in net-zero energy systems. Emissions intensity reductions for cement and concrete production can be achieved through the use of electrified cement kilns, while emissions associated with steel production can be reduced through the use of an electric arc furnace (EAF) powered by decarbonised electricity ( [[#Rissman--2020|Rissman et al. 2020]] ). Electricity can also be used to replace thermalheat such as resistive heating, EAFs, and laser sintering ( [[#Madeddu--2020|Madeddu et al. 2020]] ; [[#Rissman--2020|Rissman et al. 2020]] ). One study found that as much as 60% of the energy end-use in European industry could be met with direct electrification using existing and emerging technologies ( [[#Madeddu--2020|Madeddu et al. 2020]] ). Industry electrification for different regions will depend on the economics and availability of alternative emissions mitigation strategies such as carbon neutral fuels and CCS ( [[#Davis--2018|Davis et al. 2018]] ; [[#Madeddu--2020|Madeddu et al. 2020]] ).

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<span id="alternative-fuels-in-sectors-not-amenable-to-electrification"></span>
==== 6.6.2.4 Alternative Fuels in Sectors not Amenable to Electrification ====

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Net-zero energy systems will need to rely on alternative fuels – notably hydrogen or biofuels – in several sectors that are not amenable to electricity and otherwise hard to decarbonise ( ''medium confidence'' ). Useful carbon-based fuels (e.g., methane, petroleum, methanol), hydrogen, ammonia, or alcohols can be produced with net-zero CO 2 emissions and without fossil fuel inputs (Sections 6.4.4 and 6.4.5). For example, liquid hydrocarbons can be synthesised via hydrogenation of non-fossil carbon by processes such as Fischer-Tropsch (MacDowell et al. 2017) or by conversion of biomass ( [[#Tilman--2009|Tilman et al. 2009]] ). The resulting energy-dense fuels can serve applications that are difficult to electrify, but it is not clear if and when the combined costs of obtaining necessary feedstocks and producing these fuels without fossil inputs will be less than continuing to use fossil fuels and managing the related carbon through, for example, CCS or CDR ( [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ).

CO 2 emissions from some energy services are expected to be particularly difficult to cost-effectively avoid, among them: aviation; long-distance freight by ships; process emissions from cement and steel production; high-temperature heat (e.g., &gt;1000°C); and electricity reliability in systems with high penetration of variable renewable energy sources (NAS) ( [[#Davis--2018|Davis et al. 2018]] ; [[#Luderer--2018|Luderer et al. 2018]] ; [[#Sepulveda--2018|Sepulveda et al. 2018]] ; [[#Chiaramonti--2019|Chiaramonti 2019]] ; [[#Bataille--2020|Bataille 2020]] ; [[#Madeddu--2020|Madeddu et al. 2020]] ; [[#Rissman--2020|Rissman et al. 2020]] ; [[#Thiel--2021|Thiel and Stark 2021]] ). The literature focused on these services and sectors is growing, but remains limited, and provides minimal guidance on the most promising or attractive technological options and systems for avoiding these sectors’ emissions. Technological solutions do exist, but those mentioned in the literature are prohibitively expensive, exist only at an early stage, and/or are subject to much broader concerns about sustainability (e.g., biofuels) ( [[#Davis--2018|Davis et al. 2018]] ).

Liquid biofuels today supply about 4% of transportation energy worldwide, mostly as ethanol from grain and sugar cane and biodiesel from oil seeds and waste oils ( [[#Davis--2018|Davis et al. 2018]] ). These biofuels could conceivably be targeted to difficult-to-electrify sectors, but face substantial challenges related to their lifecycle carbon emissions, cost, and further scalability ( [[#Tilman--2009|Tilman et al. 2009]] ; [[#Staples--2018|Staples et al. 2018]] ), ( [[#6.4.2|Section 6.4.2]] ). The extent to which biomass will supply liquid fuels or high temperature heat for industry in a future net-zero energy system will thus depend on advances in conversion technology that enable use of feedstocks such as woody crops, agricultural residues, algae, and wastes, as well as competing demands for bioenergy and land, the feasibility of other sources of carbon-neutral fuels, and integration of bioenergy production with other objectives, including CDR, economic development, food security, ecological conservation, and air quality ( [[#Fargione--2010|Fargione 2010]] ; [[#Williams--2010|Williams and Laurens 2010]] ; [[#Creutzig--2015|Creutzig et al. 2015]] ; [[#Chatziaras--2016|Chatziaras et al. 2016]] ; [[#Laurens--2017|Laurens 2017]] ; [[#Lynd--2017|Lynd 2017]] ; [[#Bauer--2018|Bauer et al. 2018]] a, b; [[#Strefler--2018|Strefler et al. 2018]] ; [[#Muratori--2020b|Muratori et al. 2020b]] ; [[#Fennell--2021|Fennell et al. 2021]] ) ( [[#6.4.2.6|Section 6.4.2.6]] ).

Costs are the main barrier to synthesis of net-zero emissions fuels ( ''high confidence'' ), particularly costs of hydrogen (a constituent of hydrocarbons, ammonia, and alcohols) ( [[#6.4.5|Section 6.4.5]] ). Today, most hydrogen is supplied by steam reformation of fossil methane (CH 4 into CO 2 and H 2 ) at a cost of 1.30– USD1.50 kg –1 ( [[#Sherwin--2021|Sherwin 2021]] ). Non-fossil hydrogen can be obtained by electrolysis of water, at current costs of USD5–7 kgH 2 –1 (assuming relatively low electricity costs and high utilisation rates) ( [[#Graves--2011|Graves et al. 2011]] ; [[#DOE--2020a|DOE 2020a]] ; [[#Newborough--2020|Newborough and Cooley 2020]] ; [[#Peterson--2020|Peterson et al. 2020]] ). At these costs for electrolytic hydrogen, synthesised net-zero emissions fuels would cost at least USD1.6 per litre of diesel equivalent (or USD6 gallon –1 and USD46 GJ –1 , assuming non-fossil carbon feedstock costs of USD100 per tonne of CO 2 and low process costs of USD0.05 litre –1 or USD1.5 GJ –1 ). Similar calculations suggest that synthetic hydrocarbon fuels could currently avoid CO 2 emissions at a cost of USD936–1404 tonne –1 ( [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ). However, economies of scale are expected to bring these costs down substantially in the future ( [[#IRENA--2020c|IRENA 2020c]] ; [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ), and R&amp;D efforts are targeting 60–80% reductions in costs (to less than USD2 kg –1 (H 2 ) –1 ) possibly by use of less mature but promising technologies such as high-temperature electrolysis and thermochemical water splitting ( [[#Kuckshinrichs--2017|Kuckshinrichs et al. 2017]] ; [[#Pes--2017|Pes et al. 2017]] ; [[#Schmidt--2017|Schmidt et al. 2017]] ; [[#Saba--2018|Saba et al. 2018]] ; [[#DOE--2018|DOE, 2018]] , 2020b). Technologies capable of producing hydrogen directly from water and sunlight (photoelectrochemical cells or photocatalysts) are also under development, but are at an early stage ( [[#Nielander--2015|Nielander et al. 2015]] ; [[#DOE--2020a|DOE 2020a]] ). High hydrogen production efficiencies have been demonstrated, but costs, capacity factors, and lifetimes need to be improved in order to make such technologies feasible for net-zero emissions fuel production at scale ( [[#McKone--2014|McKone et al. 2014]] ; [[#DOE--2020a|DOE 2020a]] ; [[#Newborough--2020|Newborough and Cooley 2020]] ).

The carbon contained in net-zero emissions hydrocarbons must have been removed from the atmosphere either through DAC, or, in the case of biofuels, by photosynthesis (which could include CO 2 captured from the exhaust of biomass or biogas combustion) ( [[#Zeman--2008|Zeman and Keith 2008]] ; [[#Graves--2011|Graves et al. 2011]] ). A number of different groups are now developing DAC technologies, targeting costs of USD100 per tonne of CO 2 or less ( [[#Darton--2018|Darton and Yang 2018]] ; [[#Keith--2018|Keith et al. 2018]] ; [[#Fasihi--2019|Fasihi et al. 2019]] ).

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[[File:5d330b84bdcc07db002b9a1b3473e03c IPCC_AR6_WGIII_Figure_6_23.png]]

'''Figure 6.23 | Schematic of net-zero emissions energy system, including methods to address difficult-to-electrify sectors.''' Source: with permission from [[#Davis--2018|Davis et al. (2018)]] .

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<span id="box-6.9-the-hydrogen-economy"></span>

=== Box 6.9 | The Hydrogen Economy ===

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The phrase ‘hydrogen economy’ is often used to describe future energy systems in which hydrogen plays a prominent role. These future energy systems would not use hydrogen for all end uses; they would use hydrogen to complement other energy carriers, mainly electricity, where hydrogen might have advantages. Hydrogen could provide long-term electricity storage to support high-penetration of intermittent renewables and could enable trading and storage of electricity between different regions to overcome seasonal or production capability differences ( [[#Dowling--2020|Dowling et al. 2020]] ; [[#Sepulveda--2021|Sepulveda et al. 2021]] ). It could also be used in lieu of natural gas for peaking generation, provide process heat for industrial needs, or be used in the metal sector via direct reduction of iron ore (Chapter 11). Clean hydrogen could be used as a feedstock in the production of various chemicals and synthetic hydrocarbons. Finally, hydrogen-based fuel cells could power vehicles. Recent advances in battery storage make electric vehicles the most attractive alternative for light-duty transport. However, fuel cell technology could complement electric vehicles in supporting the decarbonisation of heavy-duty transport segments (e.g., trucks, buses, ships, and trains) (Chapter 10).

Hydrogen production costs have historically been prohibitive, but recent technological developments are bringing costs down. These developments include improvements in hydrogen production technologies in terms of efficiency and capital costs (e.g., steam methane reforming) ( [[#Alrashed--2021|Alrashed and Zahid 2021]] ; [[#Boretti--2021|Boretti and Banik 2021]] ) and the emergence of alternative production technologies such as electrolysers ( [[#Dawood--2020|Dawood et al. 2020]] ). These technological changes, along with decreasing costs of renewable power, are increasing the viability of hydrogen. Other improvements in hydrogen-based technologies are also emerging quickly. Gas turbines now run on blended fuels containing 5–95% hydrogen by volume ( [[#GE--2020|GE 2020]] ) and could operate entirely on hydrogen by 2030 ( [[#Pflug--2019|Pflug et al. 2019]] ). Fuel cell costs have decreased by 80–95% since the early 2000s, while power density and durability have improved ( [[#Jouin--2016|Jouin et al. 2016]] ; [[#IEA--2019e|IEA 2019e]] ; [[#Kurtz--2019|Kurtz et al. 2019]] ).

For hydrogen to support decarbonisation, it will need to be produced from zero-carbon or extremely low-carbon energy sources. One such production category is ‘green hydrogen’. While there is no unified definition for green hydrogen, it can be produced by the electrolysis of water using electricity generated without carbon emissions (such as renewables). Hydrogen can also be produced through biomass gasification with carbon capture and storage (BECCS), leading to negative carbon emissions ( [[#Arnaiz%20del%20Pozo--2021|Arnaiz del Pozo et al. 2021]] ). Additionally, ‘blue hydrogen’ can be produced from natural gas through the process of auto-thermal reforming (ATR) or steam methane reforming, combined with CCS technology that would absorb most of the resulting CO 2 (80–90%).

However, the potential role of hydrogen in future energy systems depends on more than just production methods and costs. For some applications, the competitiveness of hydrogen also depends on the availability of the infrastructure needed to transport and deliver it at relevant scales ( [[#Lee--2021|Lee et al. 2021]] ). Transporting hydrogen through existing gas pipelines is generally not feasible without changes to the infrastructure itself ( [[#Gumber--2018|Gumber and Gurumoorthy 2018]] ; [[#Muratori--2018|Muratori et al. 2018]] ). Existing physical barriers, such as steel embrittlement and degradation of seals, reinforcements in compressor stations, and valves, require retrofitting during the conversion to H 2 distribution or new dedicated pipelines to be constructed ( [[#Dohi--2016|Dohi et al. 2016]] ). The capacity to leverage and convert existing gas infrastructure to transport hydrogen will vary regionally, but in many cases could be the most economically viable pathway ( [[#Cerniauskas--2020|Cerniauskas et al. 2020]] ; [[#Brändle--2021|Brändle et al. 2021]] ; Brooks 2021; Wettengel 2021). Hydrogen could also be transported as liquid gas or as liquid organic hydrogen carriers such as ammonia, for which industry knowledge exists (Demir et al. 2018; Wulf et al. 2018; Hong et al. 2021). Additionally, improvements in fuel cell technologies are needed to make hydrogen-based transport economically viable. There are also safety concerns associated with the flammability ( [[#Nilsson--2017|Nilsson et al. 2017]] ) and storage ( [[#Andersson--2019|Andersson and Grönkvist 2019]] ; [[#Caglayan--2019|Caglayan et al. 2019]] ) of hydrogen which will need to be considered.

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<span id="using-less-energy-and-using-it-more-efficiently"></span>
==== 6.6.2.5 Using Less Energy and Using It More Efficiently ====

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Demand-side or demand reduction strategies include technology efficiency improvements, strategies that reduce energy consumption or demand for energy services (such as reducing the use of personal transportation, often called ‘conservation’) ( [[#Creutzig--2018|Creutzig et al. 2018]] ), and strategies such as load curtailment.

Net-zero energy systems will use energy more efficiently than those of today ( ''high confidence'' ). Energy efficiency and energy use reduction strategies are generally identified as being flexible and cost-effective, with the potential for large-scale deployment (Chapters 5, 9, 10, and 11). For this reason, existing studies find that energy efficiency and demand reduction strategies will be important contributors to net-zero energy systems ( [[#Creutzig--2018|Creutzig et al. 2018]] ; [[#Davis--2018|Davis et al. 2018]] ; [[#DeAngelo--2021|DeAngelo et al. 2021]] ). Lower demand reduces the need for low-carbon energy or alternative fuel sources.

Characterising efficiency of net-zero energy systems is problematic due to measurement challenges ( ''high confidence'' ). Efficiency itself is difficult to define and measure across full economies ( [[#Saunders--2021|Saunders et al. 2021]] ). There is no single definition of energy efficiency and the definition understandably depends on the context used ( [[#Patterson--1996|Patterson 1996]] ), which ranges from device-level efficiency all the way to the efficient use of energy throughout an economy. Broadly, energy-efficient strategies allow for the same level of services or output while using less energy. At the level of the entire economy, measures such as primary or final energy per capita or per GDP are often used as a proxy for energy efficiency; these measures reflect not only efficiency, but also many other factors such as industrial structure, endowed natural resources, consumer preferences, policies, and regulations. Energy efficiency and other demand-side strategies represent such a large set of technologies, strategies, policies, market and consumers’ responses and policies that aggregate measures can be difficult to define ( [[#Saunders--2021|Saunders et al. 2021]] ).

Measurement issues notwithstanding, virtually all studies that address net-zero energy systems assume improved energy intensity in the future ( ''high confidence'' ). The overall efficiency outcomes and the access to such improvements across different nations, however, are not clear. Energy consumption will increase over time – despite energy efficiency improvements – due to population growth and development ( [[#DeAngelo--2021|DeAngelo et al. 2021]] ).

A study ( [[#DeAngelo--2021|DeAngelo et al. 2021]] ) reviewed 153 integrated asset management scenarios that attain net-zero energy sector CO 2 emissions and found that, under a scenario with net-zero emissions: global final energy per capita lies between 21–109 GJ per person (median: 57), in comparison to 2018 global final energy use of 55 GJ per person; many countries use far more energy per capita than today as their incomes increase; global final energy use per unit of economic output ranges from 0.7–2.2 EJ per trillion USD (median: 1.5), in comparison to 5 EJ per trillion USD in 2018; and the median final energy consumption is 529 EJ. By comparison, final energy consumption would be 550 EJ if current energy consumption per capita continued under a future population of 10 billion people. Across all scenarios, total final energy consumption is higher today than in the year in which net-zero emissions are attained, and regionally, only the OECD+EU and Eurasia have lower median total final energy than in 2010.

Net-zero energy systems will be characterised by greater efficiency and more efficient use of energy across all sectors ( ''high confidence'' ). Road transportation efficiency improvements will require a shift from liquid fuels (Chapters 5 and 10). Emissions reductions will come from a transition to electricity, hydrogen, or synthetic fuels produced with low-carbon energy sources or processes. Vehicle automation, ride-hailing services, online shopping with door delivery services, and new solutions like last mile delivery with drones may result in increased service share. Lighter vehicles, a shift to public transit, and incorporation of two- and three-wheelers will be features of a net-zero energy system (Chapter 10). Teleworking and automation of work may provide reductions in driving needs. Other sectors, such as air travel and marine transportation may rely on alternative fuels such as biofuels, synthetic fuels, ammonia, produced with zero carbon energy source ( [[#6.6.2.4|Section 6.6.2.4]] ).

Under net-zero energy systems, buildings would by characterised by improved construction materials, an increase in multi-family dwellings, early retirement of inefficient buildings, smaller floor areas, and smart controls to optimise energy use in the building, namely for heating, cooling, LED lighting, and water heating (Chapter 9). End uses would utilise electricity, or potentially hydrogen, produced from zero-carbon sources. The use of electricity for heating and cooking may often be a less efficient process at converting primary energy to energy services than using natural gas, but using natural gas would require CDR in order to be considered net-zero emissions. Changes in behaviour may modestly lower demand. Most economies would have buildings with more efficient technologies powered by zero-carbon electricity, and developing economics would shift from biomass to electricity, raising their energy consumption as population and wealth increase under net-zero energy systems.

Industry has seen major efficiency improvements in the past, but many processes are now close to their thermodynamic limits. Electrification and breakthrough processes (such as producing steel with electricity and hydrogen), using recycled materials, using heat more efficiently by improving thermal insulation, and using waste heat for heat pumps, as well using advanced sensors, monitoring, and visualisation and communication technologies may provide further efficiency improvements (Chapter 11).

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<span id="greater-reliance-on-integrated-energy-system-approaches"></span>
==== 6.6.2.6 Greater Reliance on Integrated Energy System Approaches ====

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Energy systems integration refers to connected planning and operations across energy carriers, including electricity, fuels, and thermal resources. Coordinated planning could be important in lowering system costs, increasing reliability, minimising environmental impacts, and ensuring that costs of R&amp;D and infrastructure account for not just current needs but also for those of future energy systems ( [[#6.4.3|Section 6.4.3]] ). Integration includes not only the physical energy systems themselves but also simultaneous societal objectives (e.g., sustainable development goals), innovation processes (e.g., coordinating R&amp;D to increase the likelihood of beneficial technological spillovers), and other institutional and infrastructural transformations ( [[#Sachs--2019|Sachs et al. 2019]] ). Given system variability and differences in regional resources, there are economic and technical advantages to greater coordination of investments and policies across jurisdictions, sectors, and levels of government ( [[#Schmalensee--2017|Schmalensee and Stavins 2017]] ). Coordinated planning and operations can improve system economics by sharing resources, increasing the utilisation of capital-intensive assets, enhancing the geographical diversity of resource bases, and smoothing demand. But integration could require regulatory and market frameworks to facilitate and appropriate price signals to align incentives and to coordinate investments and operations.

Carbon-neutral energy systems are likely to be more interconnected than those of today ( ''high confidence'' ). The many possible feedstocks, energy carriers, and interconversion processes imply a greater need for the integration of production, transport, storage, and consumption of different fuels ( [[#Davis--2018|Davis et al. 2018]] ). For instance, electrification is expected to play an important role in decarbonising light-duty vehicles (Chapter 10, [[#6.4.3|Section 6.4.3]] ), yet the electricity and transport sectors have few direct interactions today. Systems integration and sectoral coupling are increasingly relevant to ensure that net-zero energy systems are reliable, resilient, and affordable ( [[#EPRI--2017|EPRI 2017]] ; Martin et al. 2017; [[#Buttler--2018|Buttler and Spliethoff 2018]] ; [[#O’Malley--2020|O’Malley et al. 2020]] ). Deep decarbonisation offers new opportunities and challenges for integrating different sectors as well as supply- and demand-side options. For instance, increasing electrification will change daily and seasonal load shapes, and end-use flexibilities and constraints could impact the desirability of different supply-side technologies ( [[#Brown--2018|Brown et al. 2018]] ; [[#EPRI--2019b|EPRI 2019b]] ). The feasibility of net-zero energy system configurations could depend on demonstrating cross-sector benefits like balancing VRE sources in the electricity sector, and on offering the flexibility to produce multiple products. For instance, low-emissions synthetic fuels could help to bridge stationary and mobile applications, since fuel markets have more flexibility than instantaneously balanced electricity markets due to the comparative ease and cost of large-scale, long-term storage of chemical fuels ( [[#Davis--2018|Davis et al. 2018]] ).

There are few detailed archetypes of integrated energy systems that provide services with zero- or net-negative CO 2 emissions (such as [[#Jacobson--2019|Jacobson et al. 2019]] ), so there is considerable uncertainty about integration and interactions across parts of the system. Although alternate configurations, trade-offs, and pathways are still being identified, common elements include fuels and processes like zero- or negative-CO 2 electricity generation and transmission, hydrogen production and transport, synthetic hydrocarbon production and transport, ammonia production and transport, and carbon management, where linkages across pathways could include the use of electricity to produce hydrogen via electrolysis ( [[#Smith--2016|Smith et al. 2016]] ; [[#Moore--2017|Moore 2017]] ; [[#Davis--2018|Davis et al. 2018]] ; [[#Jenkins--2018b|Jenkins et al. 2018b]] ; [[#Shih--2018|Shih et al. 2018]] ; [[#van%20Vuuren--2018|van Vuuren et al. 2018]] ). Linked analytical frameworks are increasing being used to understand the potential role for system coupling with greater temporal resolution, spatial resolution, and heterogeneity of consumer and firm decisions (Bohringer and Rutherford 2008; [[#Bistline--2017|Bistline and de la Chesnaye 2017]] ; [[#Collins--2017|Collins et al. 2017]] ; [[#Gerboni--2017|Gerboni et al. 2017]] ; [[#Santen--2017|Santen et al. 2017]] ; [[#Pye--2021|Pye et al. 2021]] ).

Challenges associated with integrating net-zero energy systems include rapid technological change, the importance of behavioural dimensions in domains with limited experience and data, policy changes and interactions, and path dependence. Technological cost and public acceptance will influence the degree of integration. Sectoral pathways will likely be adaptive and adjust based on the resolution of uncertainties over time, and the relative competitiveness will evolve as the technological frontier evolves, which is a complex and path-dependent function of deployment, R&amp;D, and inter-industry spillovers. Supply-side options interact with demand-side measures in increasingly integrated energy systems ( [[#Sorrell--2015|Sorrell 2015]] ; [[#van%20Vuuren--2018|van Vuuren et al. 2018]] ).

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<span id="carbon-dioxide-removal"></span>
==== 6.6.2.7 Carbon Dioxide Removal ====

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While CDR is likely necessary for net-zero energy systems, the scale and mix of strategies is unclear –nonetheless some combination of BECCS and DACCS are likely to be part of net-zero energy systems ( ''high confidence'' ). Studies indicate that energy-sector CDR may potentially remove 5–12 GtCO 2 annually globally in net-zero energy systems ( [[#Fuss--2018|Fuss et al. 2018]] ) (Figure 6.22; [[#6.7|Section 6.7]] ; Chapter 12). CDR is not intended as a replacement for emissions reduction, but rather as a complementary effort to offset residual emissions from sectors that are not decarbonised and from other low-carbon technologies such as fossil CCS ( [[#McLaren--2019|McLaren et al. 2019]] ; [[#Gaffney--2020|Gaffney et al. 2020]] ; [[#Iyer--2021|Iyer et al. 2021]] ).

CDR covers a broad set of methods and implementation options (Chapters 7 and 12). The two CDR methods most relevant to the energy sector are BECCS, which is used to produce energy carriers, and DACCS which is an energy user ( [[#Smith--2016|Smith et al. 2016]] ; [[#Singh--2021|Singh and Colosi 2021]] ). BECCS has value as an electricity generation technology, providing firm, dispatchable power to support electricity grids with large amounts of VRE sources, and reducing the reliance on other means to manage these grids, including electricity storage ( [[#Mac%20Dowell--2017|Mac Dowell et al. 2017]] ; [[#Bistline--2021a|Bistline and Blanford 2021a]] ). BECCS may also be used to produce liquid fuels or gaseous fuels, including hydrogen ( [[#6.4.2.6|Section 6.4.2.6]] ) ( [[#Muratori--2020b|Muratori et al. 2020b]] ). For instance, CO 2 from bio-refineries could be captured at &lt;USD45 tCO 2 –1 ( [[#Sanchez--2018|Sanchez et al. 2018]] ). Similarly, while CO 2 capture is expensive in the electricity sector, its integration with hydrogen via biomass gasification can be achieved at an incremental capital cost of 3–35% ( [[#Muratori--2020b|Muratori et al. 2020b]] ) ( [[#6.4|Section 6.4]] ). As with all uses of bioenergy, linkages to broad sustainability concerns may limit the viable development, as will the presence of high-quality geologic sinks in close proximity ( [[#Melara--2020|Melara et al. 2020]] ).

DACCS offers a modular approach to CDR ( [[#Creutzig--2019|Creutzig et al. 2019]] ), but it could be a significant consumer of energy. DAC could also interact with other elements of the energy systems as the captured CO 2 could be reused to produce low-carbon methanol and other fuels ( [[#Hoppe--2018|Hoppe et al. 2018]] ; [[#Realmonte--2019|Realmonte et al. 2019]] ; [[#Zhang--2020|Zhang and Fujimori 2020]] ). DACCS might also offer an alternative for use of excess electricity produced by variable renewables ( [[#Wohland--2018|Wohland et al. 2018]] ), though there are uncertainties about the economic performance of this integrated approach.

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=== 6.6.3 The Institutional and Societal Characteristics of Net-zero Energy Systems ===

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The transition to net-zeroenergy systems is not just technological; it requires shifts in institutions, organisations, and society more generally. As such, it involves institutional changes alongside changes in supply, technology, or markets ( [[#Andrews-Speed--2016|Andrews-Speed 2016]] , [[#Pai--2021|Pai et al. 2021]] ). Institutional relationships between governments and energy sector actors (e.g., consumers, electricity companies) affect the nature of net-zero systems, as these entities may collaborate on or dispute net-zero goals and measures to achieve them. For example, following the Fukushima disaster, Japan placed emphasis on government-utility-public cooperation on use of nuclear power as a means of reducing carbon emissions ( [[#Sklarew--2018|Sklarew 2018]] ). Institutions are instrumental in shaping net-zero energy systems in multiple ways, complemented by and interacting with the behaviours of actors and policy regimes in these systems (Figure 6.24).

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[[File:083976c0393afc4b07b3911a963008ba IPCC_AR6_WGIII_Figure_6_24.png]]

'''Figure 6.24 | A four-level framework for institutional change.''' The diagram depicts three levels of institutions (1–3) which collectively govern actor behaviours (4). Source: with permission from [[#Andrews-Speed--2016|Andrews-Speed (2016)]] .

One level of institutional interactions reflects embedded institutions, norms, beliefs, and ideas that would need to change to support net-zero energy systems. This applies, for example, to the objectives of modern economies and the potentially contradictory dynamics embedded in the concept of ‘green growth’ ( [[#Stegemann--2018|Stegemann and Ossewaarde 2018]] ; [[#Stoknes--2018|Stoknes and Rockström 2018]] ). The institutional environment – the political and legal systems that govern exchanges and protect property rights – would also need to be different in net-zero energy systems. In this setting, changing regulations or subsidies that continue to favour carbon-intensive systems over the technologies of a net-zero energy system might prove difficult ( [[#Sovacool--2017|Sovacool 2017]] ). More generally, net-zero energy systems will need new regulatory frameworks to undertake new challenges, from managing a more interconnected grid to adequately governing underground storage of CO 2 . Institutions may also govern specific transactions, such as firms or networks that supply energy fuels or services. Current actors are typically resistant to disruptions, even if such disruptions may broadly benefit society ( [[#Kungl--2015|Kungl 2015]] ; [[#Schmid--2017|Schmid et al. 2017]] ; [[#Mori--2018|Mori 2018]] ).

For example, one energy system characterised by differentiated institutional interactions is the USA, where delivery of liquid fuels is lightly regulated, while electricity delivery is closely regulated ( [[#Dworkin--2013|Dworkin et al. 2013]] ). Reforming this two-pronged system for decarbonisation would require four types of institutional change: (i) changes to the control systems that coordinate generation and transmission through a pyramidal architecture for the operational control, dispatch, and delivery of electricity with a primary emphasis on reliability; (ii) changes to the financing of central-station power plants through long-term bonds, as valued by Wall Street ratings analysts; (iii) changes to the structure of investor-owned utilities that attract private investors who expected decades of technological stability to yield long-term, low-risk revenues; and (iv) changes to regulations to restructure and limit excessive returns and easy entry of new retail competitors, all recognising local and national concerns through state and federal regulatory agencies. The example shows how decision-making and the infrastructures involved are layered, and can create ‘nested hierarchies’ where institutions fulfil multiple roles for energy governance or regulation simultaneously ( [[#Stern--2016b|Stern et al. 2016b]] ). Internationally and across different parts of the energy system, institutional challenges such as these could become even more stark and complex ( [[#Van%20de%20Graaf--2013|Van de Graaf 2013]] ).

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=== 6.6.4 Regional Circumstances and Net-zero Energy Systems ===

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Countries have flexibility to pursue options that make themost sense for their national circumstances (Figure 6.25). They may emphasise supply transformation over demand reduction; deploy different resources; engage at different levels in international energy trade; support different energy industries; focus on different energy carriers (e.g., electricity, hydrogen); or focus more on distributed or integrated systems, among others. Many factors may influence the long-term net-zero energy systems that are appropriate for any country’s national circumstances, including the following.

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[[File:417b9061006ec547d720dfd37fa8bf0b IPCC_AR6_WGIII_Figure_6_25.png]]

'''Figure 6.25 | Characteristics of regional energy systems and emissions when global energy and industrial CO''' 2 '''emissions reach net-zero.''' Regional differences are shown for: '''(a)''' residual emissions and carbon removal; '''(b)''' energy resources; '''(c)''' electrification; and '''(d)''' energy intensity. Distributions of scenarios are shown along each axis for each region. Colour scheme is shown in (a). Points represent individual scenarios from the AR6 Scenarios Database (R6 regions dataset).

'''Future technology.''' Technological transitions have often been driven by the relative merits of different technology options. Recent trends in the use of PV cells, wind power, and in batteries, for example, have been spurred by their increasing economic competitiveness ( [[#6.3|Section 6.3]] ). Yet future technology cannot be fully predicted, so it provides only a partial guide today for charting a path toward future systems.

'''Indigenous energy resources''' . Countries may emphasise approaches that take advantage of indigenous energy resources such as solar power, wind, hydroelectric resources, land for bioenergy crops, CO 2 storage capability, or fossil resources to be used with CCS. Countries with less abundant resources may put greater emphasis on demand reductions and regional integration. Countries with resource bases that are easily tradeable, like low-carbon electricity or bioenergy, may choose to trade those resources rather than use them domestically (Box 6.10, [[#6.4.3|Section 6.4.3]] , 6.4.5).

'''Regional climate''' . Climate influences heating and cooling demand, both of which influence countries’ energy demands and energy infrastructure to meet those demands ( [[#6.5|Section 6.5]] ). In addition to daily demand profiles, heating and cooling are seasonal, influencing which energy sources may serve these loads and the seasonal storage they require. Cooling is almost entirely served by electricity today, and heating has commonly been served by non-electric fuels. In low-carbon energy systems, heating may be increasingly served by electricity ( [[#6.6.4|Section 6.6.4]] ), meaning that the influence of regional climate may be strongest on countries’ electricity systems.

'''Current energy system configuration''' . Future sectoral energy demands and the potential for demand-side transformation are partially determined by existing infrastructure (e.g., building stocks, transport infrastructure). Countries with less developed or growing energy systems will have more flexibility to create the systems that best match their long-term goals, but there may be substantial challenges in transitioning directly to the most advanced low-carbon technology options, and countries may have different capacities to absorb technology from other countries.

'''Regional integration.''' Regional integration will allow countries to bridge energy gaps using external linkages, including regional electricity integration and trade in hydrogen, biomass, and other fuels. Countries with greater integration can rely more heavily on imports and may therefore rely less on indigenous resources (Box 6.10).

'''Societal preferences.''' Citizens in every country have preferences for certain technological options or mitigation approaches over others that will influence energy system choices. The public generally prefers a future energy system based largely on renewables. Preferences for non-renewable energy differ across regions and groups. For example, studies have found that people in the UK, Germany, the Netherlands, and Switzerland prefer renewable energy and personal energy efficiency and savings to nuclear, fossil fuels and CCS ( [[#Jones--2012|Jones et al. 2012]] ; [[#Scheer--2013|Scheer et al. 2013]] ; [[#Demski--2017|Demski et al. 2017]] ; [[#Bessette--2018|Bessette and Arvai 2018]] ; [[#Steg--2018|Steg 2018]] ; [[#Volken--2018|Volken et al. 2018]] ). Studies have found that people with higher education levels, higher incomes, females, and liberals prefer renewables to fossil fuels and nuclear ( [[#Van%20Rijnsoever--2015|Van Rijnsoever et al. 2015]] ; [[#Bertsch--2016|Bertsch et al. 2016]] ; [[#Blumer--2018|Blumer et al. 2018]] ; [[#Jobin--2019|Jobin et al. 2019]] ). The willingness to pay for renewable electricity differs by source ( [[#Ma--2015|Ma et al. 2015]] ; [[#Sundt--2015|Sundt and Rehdanz 2015]] ).

'''Technological leadership, economic opportunities, and growth.''' Countries may emphasise technologies in which they intend to have technological leadership and a competitive advantage. These could emerge over time or be based on current areas of opportunity or leadership. Industrial policy will influence future energy system as technological choices can benefit or hamper incumbents or new market actors.

'''Energy security.''' Countries emphasising import security will tend to rely more heavily on indigenous resources ( [[#6.3|Section 6.3]] ). Some indigenous resources may raise security of supply issues that will influence energy system configurations. Bioenergy and hydropower, for example, can be subject to import climate risks ( [[#6.5|Section 6.5]] ), and significant integration of VRE technologies will influence electricity system infrastructure and management ( [[#6.6.2|Section 6.6.2]] , Box 6.8).

'''Other factors.''' Countries will consider a wide range of other factors in building toward low-carbon energy systems. Population density, for example, will influence building and transportation energy demands; economic transitions will influence industrial energy demands. Societal priorities beyond climate, notably SDGs may influence technology choices and types of energy systems (Sections 6.3 and 6.7.7).

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=== Box 6.10 | Regional Integration of Energy Systems ===

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Energy systems are linked across countries in many ways: countries transport crude oil across the ocean in supertankers, pipelines carry oil and natural gas across country boundaries, electric power lines cross country boundaries, and countries trade industrial commodities that carry embodied energy or that are essential inputs to mitigation technologies. Future systems will generate electricity using different mixes of technologies, produce and transport different carriers (e.g., hydrogen or biofuels), and use far less fossil fuel, among other major changes. Important examples include electricity, hydrogen, and biomass.

'''Electricity system integration.''' Net-zero energy systems will rely more heavily on electricity generated from low-emissions technologies. Given the significant variations in the location of low-carbon electricity resources and the temporal variability of some renewable electricity sources, notably solar and wind power, regional electricity grids could reduce overall costs of net-zero energy systems ( [[#6.4.5|Section 6.4.5]] ). Furthermore, electricity transmission interconnections could significantly reduce local energy balancing costs and investment in peaking plants needed to meet security of supply requirements, and it could increase system resilience, especially in the case of extreme events such as heat waves or cold spells (Fasihi and Bogdanov 2016). Important challenges to regional electricity integration include geopolitical concerns from cross-border trade and societal and technological challenges associated with building new transmission lines.

'''Hydrogen trade.''' Hydrogen may play an important role in future net-zero energy systems, particularly in applications where electricity is not economically advantageous (Box 6.9). Hydrogen can be used to decarbonise regions in which it is produced, and it can also be transported long distances to facilitate decarbonisation of sectors distant from sources of low-cost supply. Methods of long-distance, high-volume hydrogen transport could include liquid storage, chemical carriers, and gaseous delivery via pipelines ( [[#6.4.5|Section 6.4.5]] ). In net-zero systems with substantial wind and solar power generation, hydrogen can be generated through electrolysis and then shipped to other locations. Important challenges to hydrogen trade include cost-effective low-carbon production, cost of delivery infrastructure, storage, and end-use technology costs and safety.

'''Trade in biomass.''' Biomass may also play an important role in net-zero energy systems ( [[#6.6.4|Section 6.6.4]] , Chapter 3). Large-scale bioenergy production and consumption is likely to trigger global biomass trade. Global bioenergy trade volumes presently exceed 1 EJ yr –1 , of which 60% is directly traded for energy purposes ( [[#Proskurina--2019a|Proskurina et al. 2019a]] ). Established trade mechanisms include wood pellet transport, ethanol, and biodiesel ( [[#Proskurina--2019b|Proskurina et al. 2019b]] ). In a net-zero global energy system, bioenergy trade could be greater than current trade of coal or natural gas, but less than that of petroleum ( [[#Sharmina--2017|Sharmina et al. 2017]] ; Mandley et al. 2020). Some studies indicate

Box 6.10

that Latin America and Africa could become key exporting regions, with the EU, the USA, and East Asia emerging as key importers ( [[#Alsaleh--2018|Alsaleh and Abdul-Rahim 2018]] ; [[#Rentizelas--2019|Rentizelas et al. 2019]] ). Studies have found that net bioenergy exports could be as high as 10% of GDP for some Latin American countries, while other regions like the EU may be faced with burgeoning import reliance ( [[#Daioglou--2020b|Daioglou et al. 2020b]] ; [[#Mahlknecht--2020|Mahlknecht et al. 2020]] ). In addition to challenges associated with bioenergy production ( [[#6.4|Section 6.4]] and Chapter 7), important challenges to biomass trade include differences in sustainability criteria and land/biomass definitions in different jurisdictions, and difficulties in establishing consistent monitoring and auditing systems ( [[#Lamers--2016|Lamers et al. 2016]] ).

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