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

==== 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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