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

=== 6.4.2 Energy Sources and Energy Conversion ===

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==== 6.4.2.1 Solar Energy ====

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Solar photovoltaic (PV) is increasingly competitive with other forms of electricity generation, and is the low-cost option in many applications ( ''high confidence'' ). Costs have declined by 62% since 2015 ( ''high confidence'' ) and are anticipated to decline by an additional 16% by 2030 if current trends continue ( ''low confidence, medium evidence'' ). Key areas for continued improvement are grid integration and non-module costs for rooftop systems ( ''high confidence'' ). Most deployment is now utility-scale ( ''high confidence'' ). Global future potential is not limited by solar irradiation, but by grid integration needed to address its variability, as well as access to finance, particularly in developing countries ( ''high confidence'' ).

The global technical potential of direct solar energy far exceeds that of any other renewable energy resource and is well beyond the total amount of energy needed to support ambitious mitigation over the current century ( ''high confidence'' ). Estimates of global solar resources have not changed since the IPCC’s Fifth Assessment Report (AR5) ( [[#Lewis--2007|Lewis 2007]] ; [[#Besharat--2013|Besharat et al. 2013]] ) even as precision and near-term forecasting have improved ( [[#Diagne--2013|Diagne et al. 2013]] ; [[#Abreu--2018|Abreu et al. 2018]] ). Approximately 120,000 TW of sunlight reaches the Earth’s surface continuously, almost 10,000 times average world energy consumption; factoring in competition for land use leaves a technical potential of about 300 PWh yr –1 (1080 EJ yr –1 ) for solar PV, roughly double current consumption ( [[#Dupont--2020|Dupont et al. 2020]] ). The technical potential for concentrating solar power (CSP) is estimated to be 45–82 PWh yr –1 (162–295 EJ yr –1 ) ( [[#Dupont--2020|Dupont et al. 2020]] ). Areas with the highest solar irradiation are: western South America; northern, eastern and southwestern Africa; and the Middle East and Australia (Figure 6.7) ( [[#Prăvălie--2019|Prăvălie et al. 2019]] ).

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[[File:f7827e161a3e29fa2c66349a019751aa IPCC_AR6_WGIII_Figure_6_7.png]]

'''Figure 6.7 |Distribution of the daily mean global horizontal irradiation (GHI, kWh m''' –2 '''day''' –1 ''').''' Source: Global Solar Atlas ( [[#ESMAP--2019|ESMAP 2019]] ).

In many parts of the world, the cost of electricity from PV is below the cost of electricity generated from fossil fuels; in some, it is below the operating costs of electricity generated from fossil fuels ( ''high confidence'' ). The weighted average cost of PV in 2019 was USD68 MWh –1 , near the bottom of the range of fossil fuel prices ( [[#IRENA--2019b|IRENA 2019b]] ). The cost of electricity from PV has fallen by 89% since 2000 and 69% since AR5, at a rate of –16% per year. The 5:95 percentile range for PV in 2019 was USD52–190 MWh –1 ( [[#IRENA--2021b|IRENA 2021b]] ). Differences in solar insolation, financing costs, equipment acquisition, installation labour, and other sources of price dispersion explain this range ( [[#Nemet--2016|Nemet et al. 2016]] ; [[#Vartiainen--2020|Vartiainen et al. 2020]] ) and scale. For example, in India, rooftop installations cost 41% more than utility-scale installations, and commercial-scale costs are 39% higher than utility-scale. Significant differences in regional cost persist ( [[#Kazhamiaka--2017|Kazhamiaka et al. 2017]] ; [[#Vartiainen--2020|Vartiainen et al. 2020]] ), with particularly low prices in China, India, and parts of Europe. Globally, the range of global PV costs is quite similar to the range of coal and natural gas prices.

PV costs (Figure 6.8) have fallen for various reasons: lower silicon costs, automation, lower margins, automation, higher efficiency, and a variety of incremental improvements ( [[#Fu--2018|Fu et al. 2018]] ; [[#Green--2019|Green 2019]] ) (Chapter 16). Increasingly, the costs of PV electricity are concentrated in the installation and related ‘soft costs’ (marketing, permitting) associated with the technology rather than in the modules themselves, which now account for only 30% of installed costs of rooftop systems ( [[#O’Shaughnessy--2019|O’Shaughnessy et al. 2019]] ; [[#IRENA--2021b|IRENA 2021b]] ). Financing costs are a significant barrier in developing countries ( [[#Ondraczek--2015|Ondraczek et al. 2015]] ) and growth there depends on access to low-cost finance ( [[#Creutzig--2017|Creutzig et al. 2017]] ).

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[[File:8ce80f0ff3ac41fcc2dfd6d76e3ddd42 IPCC_AR6_WGIII_Figure_6_8.png]]

'''Figure 6.8 | Levelised costs of electricity (LCOE) of solar energy technologies 2000–2020.''' Range of fossil fuel LCOE indicated as dashed lines USD50–177 MWh –1 . Linear fit lines were applied to data for AR4–AR5 and post-AR5 (2012). Yellow dots are capacity-weighted global averages for utility-scale installations. The blue area shows the range between the 5th and 95th percentile in each year. Data: [[#IRENA--2021b|IRENA (2021b)]] .

CSP costs have also fallen, albeit at about half the rate of PV: –9% yr –1 since AR5. The lowest prices for CSP are now competitive with more expensive fossil fuels, although the average CSP cost is above the range for fossil-based power generation. Other data sources put recent CSP costs at USD120 MWh –1 , in the middle of the fossil range (Lilliestam et al. 2020). Continuing the pace of change since AR5 will make CSP competitive with fossil fuels in sunny locations, although it will be difficult for CSP to compete with PV and even hybrid PV-battery systems. CSP electricity can be more valuable, however, because CSP systems can store heat longer than PV battery systems.

The share of total costs of PV-intensive electricity systems attributed to integration costs has been increasing but can be reduced by enhancing grid flexibility ( ''high confidence'' ) (Sections 6.4.3 and 6.6, and Box 6.8). The total costs of PV include grid integration, which varies tremendously depending on PV’s share of electricity, other supply sources like wind, availability of storage, transmission capacity, and demand flexibility (Heptonstall and Gross 2020). Transmission costs can add USD1–10 MWh –1 or 3–33% to the cost of utility-scale PV ( [[#Gorman--2019|Gorman et al. 2019]] ). Distributed (rooftop) PV involves a broader set of grid integration costs – including grid reinforcement, voltage balancing and control, and impacts on other generations – and has a larger range of integration costs from USD2–25 MWh –1 , which is –3% to +37% ( [[#Hirth--2015|Hirth et al. 2015]] ; [[#Wu--2015|Wu et al. 2015]] ; [[#Gorman--2019|Gorman et al. 2019]] ). Other meta-analyses put the range at USD1–7 MWh –1 in the USA (Luckow et al. 2015.; [[#Wiser--2017|Wiser et al. 2017]] ), while a comprehensive study put the range at USD12–18 MWh –1 for up to 35% renewables and USD25–46 MWh –1 above 35% renewables (Heptonstall and Gross 2020). Increased system flexibility can reduce integration costs of solar energy ( [[#Wu--2015|Wu et al. 2015]] ) including storage, demand response, sector-coupling ( [[#Brown--2018|Brown et al. 2018]] ; [[#Bogdanov--2019|Bogdanov et al. 2019]] ), and increase complementarity between wind and solar ( [[#Heide--2010|Heide et al. 2010]] ) (Sections 6.4.3 and 6.4.4).

Since solar PV panels have very low operating costs, they can, at high penetrations and in the absence of adequate incentives to shift demand, depress prices in wholesale electricity markets, making it difficult to recoup investment, and potentially reducing incentives for new installations ( [[#Hirth--2013|Hirth 2013]] ; [[#Millstein--2021|Millstein et al. 2021]] ). Continued cost reductions help address this issue of value deflation, but only partially. Comprehensive solutions depend on adding transmission and storage ( [[#Das--2020|Das et al. 2020]] ) and, more fundamentally, adjustments to electricity market design ( [[#Roques--2017|Roques and Finon 2017]] ; [[#Bistline--2019|Bistline and Young 2019]] ).

The most important ways to minimise PV’s impact on the environment lie in recycling materials at end of life and making smart land-use decisions ( ''medium confidence'' ). A comprehensive assessment of PV’s environmental impacts requires lifecycle analysis (LCA) of resource depletion, land-use, ecotoxicity, eutrophication, acidification, ozone, and particulates, among other things ( [[#Mahmud--2018|Mahmud et al. 2018]] ). LCA studies show that solar PVs produce far less CO 2 per unit of electricity than fossil generation, but PV CO 2 emissions vary due to the carbon intensity of manufacturing energy and offset electricity (Grant and Hicks 2020). Concerns about systemic impacts, such as reducing the Earth’s albedo by covering surfaces with dark panels, have shown to be trivial compared to the mitigation benefits ( [[#Nemet--2009|Nemet 2009]] ) (Box 6.7). Even though GHG LCA estimates span a considerable range of 9–250 gCO 2 kWh –1 ( [[#de%20Wild-Scholten--2013|de Wild-Scholten 2013]] ; [[#Kommalapati--2017|Kommalapati et al. 2017]] ), recent studies that reflect higher efficiencies and manufacturing improvements find lower lifecycle emissions, including a range of 18–60 gCO 2 kWh –1 ( [[#Wetzel--2015|Wetzel and Borchers 2015]] ) and central estimates of 80 gCO 2 kWh –1 ( [[#Hou--2016|Hou et al. 2016]] ), 50 gCO 2 kWh –1 ( [[#Nugent--2014|Nugent and Sovacool 2014]] ), and 20 gCO 2 kWh –1 ( [[#Louwen--2016|Louwen et al. 2016]] ). These recent values are an order of magnitude lower than coal, and natural gas and further decarbonisation of the energy system will make them lower still. Thin films and organics produce half the lifecycle emissions of silicon wafer PV, mainly because they use less material ( [[#Lizin--2013|Lizin et al. 2013]] ; [[#Hou--2016|Hou et al. 2016]] ). Novel materials promise even lower environmental impacts, especially with improvements to their performance ratios and reliability ( [[#Gong--2015|Gong et al. 2015]] ; [[#Muteri--2020|Muteri et al. 2020]] ). Higher efficiencies, longer lifetimes, sunny locations, less carbon-intensive manufacturing inputs, and shifting to thin films could reduce future lifecycle impacts.

Another environmental concern with large PV power plants is the conversion of land to collect solar energy ( [[#Hernandez--2015|Hernandez et al. 2015]] ). Approximately 2 hectares of land are needed for 1 MW of solar electricity capacity ( [[#Perpiña%20Castillo--2016|Perpiña Castillo et al. 2016]] ; [[#Kabir--2018|Kabir et al. 2018]] ); at 20% efficiency, a square of PV panels of 550 km by 550 km, comprising 0.2% of Earth’s land area, could meet global energy demand. Land conversion can have local impacts, especially near cities and where land used for solar competes with alternative uses, such as agriculture. Large installations can also adversely impact biodiversity ( [[#Hernandez--2014|Hernandez et al. 2014]] ), especially where the above-ground vegetation is cleared and soils are typically graded. Landscape fragmentation creates barriers to the movement of species. However, a variety of means have emerged to mitigate land use issues. Substitution among renewables can reduce land conversion ( [[#Tröndle--2020|Tröndle 2020]] ). Solar can be integrated with other uses through ‘agrivoltaics’ (the use of land for both agriculture and solar production) ( [[#Dupraz--2011|Dupraz et al. 2011]] ) by, for example, using shade-tolerant crops (Dinesh and Pearce 2016). Combining solar and agriculture can also create income diversification, reduced drought stress, higher solar output due to radiative cooling, and other benefits ( [[#Elamri--2018|Elamri et al. 2018]] ; [[#Hassanpour%20Adeh--2018|Hassanpour Adeh et al. 2018]] ; [[#Barron-Gafford--2019|Barron-Gafford et al. 2019]] ). PV installations floating on water also avoid land-use conflicts ( [[#Sahu--2016|Sahu et al. 2016]] ; [[#Lee--2020|Lee et al. 2020]] ), as does dual-use infrastructure, such as landfills ( [[#Jäger-Waldau--2020|Jäger-Waldau 2020]] ) and reservoirs where evaporation can also be reduced ( [[#Farfan--2018|Farfan and Breyer 2018]] ).

Material demand for PV will likely increase substantially to limit warming to well below 2°C, but PV materials are widely available, have possible substitutes, and can be recycled ( ''medium confidence'' ) (Box 6.4). The primary materials for PV are silicon, copper, glass, aluminium, and silver – the costliest being silicon, and glass being the most essential by mass, at 70%. None of these materials is considered to be either critical or potentially scarce ( [[#IEA--2020e|IEA 2020e]] ). Thin-film cells, such as amorphous silicon, cadmium telluride and copper indium gallium diselenide (CIGS), use far less material (though they use more glass), but account for less than 10% of the global solar market. Other thin-films, such as those based on perovskites, organic solar cells, or earth-abundant, non-toxic materials such as kesterites, either on their own, or layered on silicon, could further reduce material use per energy produced (Box 6.4).

After a typical lifetime of 30 years of use, PV modules can be recycled to prevent environmental contamination from the toxic materials within them, reusing valuable materials and avoiding waste accumulation. Recycling allows the reuse of nearly all – 83% in one study – of the components of PV modules, other than plastics ( [[#Ardente--2019|Ardente et al. 2019]] ) and would add less than 1% to lifecycle GHG emissions ( [[#Latunussa--2016|Latunussa et al. 2016]] ). Glass accounts for 70% of the mass of a solar cell and is relatively easy to recycle. Recycling technology is advancing, but the scale and share of recycling is still small (Li et al. 2020d). By 2050, however, end-of-life PV could total 80 MT and comprise 10% of global electronic waste ( [[#Stolz--2017|Stolz and Frischknecht 2017]] ), although most of it is glass. IEA runs a programme to enable PV recycling by sharing best practices to minimise recycling lifecycle impacts. Ensuring that a substantial amount of panels are recycled at end of life will likely require policy incentives, as the market value of the recovered materials, aside from aluminium and copper, is likely to be too low to justify recycling on its own ( [[#Deng--2019|Deng et al. 2019]] ). A near-term priority is maximising the recovery of silver, silicon, and aluminium, the most valuable PV material components ( [[#Heath--2020|Heath et al. 2020]] ).

Many alternative PV materials are improving in efficiency and stability, providing longer-term pathways for continued PV costs reductions and better performance ( ''high confidence'' ). While solar PV based on semi-conductors constructed from wafers of silicon still captures 90% of the market, new designs and materials have the potential to reduce costs further, increase efficiency, reduce resource use, and open new applications. The most significant technological advance within silicon PV in the past 10 years has been the widespread adoption of the passivated emitter and rear cell (PERC) design ( [[#Green--2015|Green 2015]] ), which now accounts for the majority of production. This advance boosts efficiency over traditional aluminium backing by increasing reflectivity within the cell and reducing electron-hole recombination ( [[#Blakers--2019|Blakers 2019]] ). Bifacial modules increase efficiency by using reflected light from the ground or roof on the backside of modules ( [[#Guerrero-Lemus--2016|Guerrero-Lemus et al. 2016]] ). Integrating PV into buildings can reduce overall costs and improve building energy performance ( [[#Shukla--2016|Shukla et al. 2016]] ). Concentrating PV uses lenses or mirrors that collect and concentrate light onto high efficiency PV cells ( [[#Li--2020a|Li et al. 2020a]] ). Beyond crystalline silicon, thin films of amorphous silicon, cadmium telluride, and copper indium gallium selenide (among others) have the potential for much lower costs while their efficiencies have increased ( [[#Green--2019|Green et al. 2019]] ). Perovskites, inexpensive and easy to produce crystalline structures, have increased in efficiency by a factor of six in the past decade; the biggest challenge is light-induced degradation as well as finding lead-free efficient compounds, or establishing lead recycling at the end of the lifecycle of the device ( [[#Petrus--2017|Petrus et al. 2017]] ; [[#Chang--2018|Chang et al. 2018]] ; [[#Wang--2019b|Wang et al. 2019b]] ; [[#Zhu--2020|Zhu et al. 2020]] ). Organic solar cells are made of carbon-based semiconductors like the ones found in the displays made from organic light emitting diodes (OLEDs) and can be processed in thin films on large areas with scalable and fast coating processes on plastic substrates. The main challenges are raising the efficiency and improving their lifetime ( [[#Ma--2020|Ma et al. 2020]] ; [[#Riede--2021|Riede et al. 2021]] ). Quantum dots, spherical semi-conductor nanocrystals, can be tuned to absorb specific wavelengths of sunlight, giving them the potential for high efficiency with very little material use ( [[#Kramer--2015|Kramer et al. 2015]] ). A common challenge for all emerging solar cell technologies is developing the corresponding production equipment. Hybrids of silicon with layers of quantum dots and perovskites have the potential to take advantage of the benefits of all three, although those designs require that these new technologies have stability and scale that match those of silicon ( [[#Chang--2017|Chang et al. 2017]] ; [[#Palmstrom--2019|Palmstrom et al. 2019]] ). This broad array of alternatives to making PV from crystalline silicon offer realistic potential for lower costs, reduced material use, and higher efficiencies in future years ( [[#Victoria--2021|Victoria et al. 2021]] ).

Besides PV, alternative solar technologies exist, including CSP, which can provide special services in high-temperature heat and diurnal storage, even if it is more costly than PV and its potential for deployment is limited. CSP uses reflective surfaces, such as parabolic mirrors, to focus sunlight on a receiver to heat a working fluid, which is subsequently transformed into electricity ( [[#Islam--2018|Islam et al. 2018]] ). Solar heating and cooling are also well established technologies, and solar energy can be utilised directly for domestic or commercial applications such as drying, heating, cooling, and cooking ( [[#Ge--2018|Ge et al. 2018]] ). Solar chimneys, (still purely conceptual), heat air using large transparent greenhouse-like structures and channel the warm air to turbines in tall chimneys ( [[#Kasaeian--2017|Kasaeian et al. 2017]] ). Solar energy can also be used to produce solar fuels, for example, hydrogen or synthetic gas (syngas) (Montoya et al. 2016; [[#Nocera--2017|Nocera 2017]] ; [[#Detz--2018|Detz et al. 2018]] ). In addition, research proceeds on space-based solar PV, which takes advantage of high insolation and a continuous solar resource ( [[#Kelzenberg--2018|Kelzenberg et al. 2018]] ), but faces the formidable obstacle of developing safe, efficient, and inexpensive microwave or laser transmission to the Earth’s surface ( [[#Yang--2016|Yang et al. 2016]] ). CSP is the most widely adopted of these alternative solar technologies.

Like PV, CSP facilities can deliver large amounts of power (up to 200 MW per unit) and maintain substantial thermal storage, which is valuable for load balancing over the diurnal cycle ( [[#McPherson--2020|McPherson et al. 2020]] ). However, unlike PV, CSP can only use direct sunlight, constraining its cost-effectiveness to North Africa, the Middle East, Southern Africa, Australia, the Western USA, parts of South America (Peru, Chile), and the Western part of China ( [[#Deng--2015|Deng et al. 2015]] ; [[#Dupont--2020|Dupont et al. 2020]] ). Parabolic troughs, central towers and parabolic dishes are the three leading solar thermal technologies ( [[#Wang--2017d|Wang et al. 2017d]] ). Parabolic troughs represented approximately 70% of new capacity in 2018 with the balance made up by central tower plants ( [[#Islam--2018|Islam et al. 2018]] ). Especially promising research directions are on tower-based designs that can achieve high temperatures, useful for industrial heat and energy storage ( [[#Mehos--2017|Mehos et al. 2017]] ), and direct steam generation designs ( [[#Islam--2018|Islam et al. 2018]] ). Costs of CSP have fallen by nearly half since AR5 (Figure 6.8) albeit at a slower rate than PV. Since AR5, almost all new CSP plants have storage (Figure 6.9) ( [[#Thonig--2020|Thonig 2020]] ).

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'''Figure 6.9 | CSP plants by storage capacity in hours (vertical), year of installation (horizontal), and size of plant in MW (circle size).''' Since AR5, almost all new CSP plants have storage ( [[#Thonig--2020|Thonig 2020]] ). Source: with permission from https://csp.guru/metadata.html .

Solar energy elicits favourable public responses in most countries ( ''high confidence'' ) ( [[#Mcgowan--2005|Mcgowan and Sauter 2005]] ; [[#Ma--2015|Ma et al. 2015]] ; [[#Hanger--2016|Hanger et al. 2016]] ; [[#Bessette--2018|Bessette and Arvai 2018]] ; [[#Jobin--2018|Jobin and Siegrist 2018]] ; [[#Roddis--2019|Roddis et al. 2019]] ; [[#Hazboun--2020|Hazboun and Boudet 2020]] ) ''.'' Solar energy is perceived as clean and environmentally friendly with few downsides ( [[#Faiers--2006|Faiers and Neame 2006]] ; [[#Whitmarsh--2011b|Whitmarsh et al. 2011b]] ). Key motivations for homeowners to adopt PV systems are expected financial gains, environmental benefits, the desire to become more self-sufficient, and peer expectations ( [[#Korcaj--2015|Korcaj et al. 2015]] ; [[#Vasseur--2015|Vasseur and Kemp 2015]] ; [[#Palm--2017|Palm 2017]] ). Hence, the observability of PV systems can facilitate adoption ( [[#Boudet--2019|Boudet 2019]] ). The main barriers to the adoption of solar PV by households are its high upfront costs, aesthetics, landlord-tenant incentives, and concerns about performance and reliability ( [[#Faiers--2006|Faiers and Neame 2006]] ; [[#Whitmarsh--2011b|Whitmarsh et al. 2011b]] ; [[#Vasseur--2015|Vasseur and Kemp 2015]] ).

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==== 6.4.2.2 Wind Energy ====

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Wind power is increasingly competitive with other forms of electricity generation and is the low-cost option in many applications ( ''high confidence'' ). Costs have declined by 18% and 40% on land and offshore since 2015 ( ''high confidence'' ), and further reductions can be expected by 2030 ( ''medium confidence'' ). Critical areas for continued improvement are technology advancements and economies of scale ( ''high confidence'' ). Global future potential is primarily limited by onshore land availability in wind power-rich areas, lack of supporting infrastructure, grid integration, and access to finance (especially in developing countries) ( ''high confidence'' ).

Energy from wind is abundant, and the estimated technical potentials surpass the total amount of energy needed to limit warming to well below 2°C ( ''high confidence'' ). Recent global estimates of potentially exploitable wind energy resource are in the range of 557–717 PWh yr –1 (2005–2580 EJ yr –1 ) ( [[#Eurek--2017|Eurek et al. 2017]] ; [[#Bosch--2017|Bosch et al. 2017]] , 2018; [[#McKenna--2022|McKenna et al. 2022]] ), or 20–30 times the 2017 global electricity demand. Studies have suggested that ‘bottom-up’ approaches may overestimate technical potentials ( [[#Miller--2015|Miller et al. 2015]] ; [[#Kleidon--2020|Kleidon and Miller 2020]] ). But even in the most conservative ‘top-down’ approaches, the technical wind potential surpasses the amount needed to limit warming to well below 2°C ( [[#Bosch--2017|Bosch et al. 2017]] ; [[#Eurek--2017|Eurek et al. 2017]] ; [[#Volker--2017|Volker et al. 2017]] ). The projected climate change mitigation from wind energy by 2100 ranges from 0.3°C–0.8°C depending on the precise socio-economic pathway and wind energy expansion scenario followed ( [[#Barthelmie--2021|Barthelmie and Pryor 2021]] ). Wind resources are unevenly distributed over the globe and by time of the year ( [[#Petersen--2012|Petersen and Troen 2012]] ), but potential hotspots exist on every continent (Figure 6.10) as expressed by the wind power density (a quantitative measure of wind energy available at any location). Technical potentials for onshore wind power vary considerably, often because of inconsistent assessments of suitability factors ( [[#McKenna--2020|McKenna et al. 2020]] ). The potential for offshore wind power is larger than for onshore because offshore wind is stronger and less variable ( [[#Bosch--2018|Bosch et al. 2018]] ). Offshore wind is more expensive, however, because of higher costs for construction, maintenance, and transmission. Wind power varies at a range of time scales, from annual to sub-seconds; the effects of local short-term variability can be offset by power plant control, flexible grid integration, and storage ( [[#Barra--2021|Barra et al. 2021]] ) ( [[#6.4.3|Section 6.4.3]] ). In some regions, interannual variations in wind energy resources could be important for optimal power system design ( [[#Wohland--2019a|Wohland et al. 2019a]] ; [[#Coker--2020|Coker et al. 2020]] ).

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'''Figure 6.10 | Mean wind power density [W m''' –2 '''] at 100 m above ground level over land and within 100 km of the coastline.''' Source: Global Wind Atlas, available at: https://globalwindatlas.info/ .

Wind power cost reductions (Figure 6.11) are driven mainly by larger capacity turbines, larger rotor diameters and taller hub heights – larger swept areas increase the energy captured and the capacity factors for a given wind speed; taller towers provide access to higher wind speeds ( [[#Beiter--2021|Beiter et al. 2021]] ). All major onshore wind markets have experienced rapid growth in both rotor diameter (from 81.2 m in 2010 to 120 m in 2020) ( [[#IRENA--2021b|IRENA 2021b]] ), and average power ratings (from 1.9 MW in 2010 to 3 MW in 2020). The generation capacity of offshore wind turbines grew by a factor of 3.7 in less than two decades, from 1.6 MW in 2000 to 6 MW in 2020 ( [[#Wiser--2021|Wiser et al. 2021]] ). Floating foundations could revolutionise offshore wind power by tapping into the abundant wind potential in deeper waters. This technology is particularly important for regions where coastal waters are too deep for fixed-bottom wind turbines. Floating wind farms potentially offer economic and environmental benefits compared with fixed-bottom designs due to less-invasive activity on the seabed during installation, but the long-term ecological effects are unknown and meteorological conditions further offshore and in deeper waters are harsher on wind turbine components ( [[#IRENA--2019c|IRENA 2019c]] ). A radical new class of wind energy converters has also been conceived under the name of airborne wind energy systems that can harvest strong, high-altitude winds (typically between 200–800m), which are inaccessible by traditional wind turbines ( [[#Cherubini--2015|Cherubini et al. 2015]] ). This technology has seen development and testing of small devices ( [[#Watson--2019|Watson et al. 2019]] ).

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'''Figure 6.11 | Global weighted average total installed costs, capacity factors, and LCOE for onshore (top) and offshore (bottom) wind power of existing power plants per year (2010–2020).''' The shaded area represents the 5th and 95th percentiles, and the red dashed line represents the fossil fuel cost range. Source: with permission from [[#IRENA--2021a|IRENA (2021a)]] .

Wind capacity factors have increased over the last decade (Figure 6.11). The capacity factor for onshore wind farms increased from 27% in 2010 to 36% in 2020 ( [[#IRENA--2021a|IRENA 2021a]] ). The global average offshore capacity factor has decreased from a peak of 45% in 2017. This has been driven by the increased share of offshore development in China, where projects are often near-shore and use smaller wind turbines than in Europe ( [[#IRENA--2021b|IRENA 2021b]] ). Improvements in capacity factors also come from increased functionality of wind turbines and wind farms. Manufactures can adapt the wind turbine generator to the wind conditions. Turbines for windy sites have smaller generators and smaller specific capacity per rotor area, and therefore operate more efficiently and reach full capacity for a longer time period ( [[#Rohrig--2019|Rohrig et al. 2019]] ).

Electricity from onshore wind is less expensive than electricity generated from fossil fuels in a growing number of markets ( ''high confidence'' ). The global average LCOE onshore declined by 38% from 2010 to 2020 (Figure 6.11), reaching USD0.039 kWh –1 . However, the decrease in cost varies substantially by region. Since 2014, wind costs have declined more rapidly than the majority of experts predicted ( [[#Wiser--2021|Wiser et al. 2021]] ). New modelling projects onshore wind LCOE of USD.037 kWh –1 by 2030 ( [[#Junginger--2020a|Junginger et al. 2020a]] ), and additional reductions of 37–39% have been predicted by 2050 ( [[#Wiser--2021|Wiser et al. 2021]] ). The future cost of offshore wind is more uncertain because other aspects besides increases in capacity factors influence the cost ( [[#Junginger--2020b|Junginger et al. 2020b]] ).

The cost of the turbine (including the towers) makes up the largest component of wind LCOE. Total installed costs for both onshore and offshore wind farms have decreased since 2015 (Figure 6.11), but the total installed costs for onshore wind projects are very site- and market-specific, as reflected in the range of LCOEs. China, India, and the USA have experienced the largest declines in total installed costs. In 2020, typical country-average total installed costs were around USD1150 kW –1 in China and India, and between USD1403–2472 kW –1 elsewhere ( [[#IRENA--2021b|IRENA 2021b]] ). Total installed costs of offshore wind farms declined by 12% between 2010 and 2020. But, because some of the new offshore wind projects have moved to deeper waters and further offshore, there are considerable year-to-year variations in their price ( [[#IRENA--2021b|IRENA 2021b]] ). Projects outside China in recent years have typically been built in deeper waters (10–55 m) and up to 120 km offshore, compared to around 10 m in 2001–2006, when distances rarely exceeded 20 km. With the shift to deeper waters and sites further from ports, the total installed costs of offshore wind farms rose, from an average of around USD2500 kW –1 in 2000 to around USD5127 kW –1 by 2011–2014, before falling to around USD3185 kW –1 in 2020 ( [[#IRENA--2020a|IRENA 2020a]] ). The full cost of wind power includes the transmission and system integration costs (Sections 6.4.3 and 6.4.6). A new technology in development is the co-location of wind and solar PV power farms, also known as hybrid power plants. Co-locating wind, solar PV, and batteries can lead to synergies in electricity generation, infrastructure, and land usage, which may lower the overall plant cost compared to single technology systems ( [[#Lindberg--2021|Lindberg et al. 2021]] ).

Wind power plants pose relatively low environmental impact, but sometimes locally significant ecological effects ( ''high confidence'' ). The environmental impact of wind technologies, including CO 2 emissions, is concentrated in the manufacturing, transport, and building stage and in disposal as the end-of-life of wind turbines is reached (Liu and Barlow 2017; [[#Mishnaevsky--2021|Mishnaevsky 2021]] ). The operation of wind turbines produces no waste or pollutants. The LCA for wind turbines is strongly influenced by the operating lifetime, quality of wind resources, conversion efficiency, and size of the wind turbines ( [[#Kaldellis--2017|Kaldellis and Apostolou 2017]] ; [[#Laurent--2018|Laurent et al. 2018]] ). All wind power technologies repay their carbon footprint in less than a year ( [[#Bonou--2016|Bonou et al. 2016]] ).

Wind farms can cause local ecological impacts, including on animal habitat and movements, biological concerns, bird and bat fatalities from collisions with rotating blades, and health concerns ( [[#Morrison--2004|Morrison and Sinclair 2004]] ). The impacts on animal habitats and collisions can be resolved or reduced by selectively stopping some wind turbines in high-risk locations, often without affecting the productivity of the wind farm ( [[#de%20Lucas--2012|de Lucas et al. 2012]] ). Many countries now require environmental studies of impacts of wind turbines on wildlife prior to project development, and, in some regions, shutdowns are required during active bird migration ( [[#de%20Lucas--2012|de Lucas et al. 2012]] ). Offshore wind farms can also impact migratory birds and other sea species ( [[#Hooper--2017|Hooper et al. 2017]] ). Floating foundations pose lower environmental impacts at build stage ( [[#IRENA--2019c|IRENA 2019c]] ), but their cumulative long-term impacts are unclear ( [[#Goodale--2016|Goodale and Milman 2016]] ). Recent studies find weak associations between wind farm noise and measures of long-term human health ( [[#Poulsen--2018a|Poulsen et al. 2018a]] , b, 2019a, b).

Public support for onshore and particularly offshore wind energy is generally high, although people may oppose specific wind farm projects ( ''high confidence'' ) (e.g., Bell et al. 2005; Batel and Devine-Wright 2015; [[#Rand--2017|Rand and Hoen 2017]] ; [[#Steg--2018|Steg 2018]] ). People generally believe that wind energy is associated with environmental benefits and that it is relatively cheap. Yet, some people believe wind turbines can cause noise and visual aesthetic pollution, threaten places of symbolic value ( [[#Devine-Wright--2020|Devine-Wright and Wiersma 2020]] ; [[#Russell--2020|Russell et al. 2020]] ), and have adverse effects on wildlife ( [[#Bates--2015|Bates and Firestone 2015]] ), which challenges public acceptability ( [[#Rand--2017|Rand and Hoen 2017]] ). Support for local wind projects is higher when people believe fair decision-making procedures have been implemented ( [[#Dietz--2008|Dietz and Stern 2008]] ; [[#Aitken--2010a|Aitken 2010a]] ). Evidence is mixed whether distance from wind turbines or financial compensation increases public acceptability of wind turbines ( [[#Cass--2010|Cass et al. 2010]] ; [[#Rand--2017|Rand and Hoen 2017]] ; [[#Rudolph--2018|Rudolph et al. 2018]] ; [[#Hoen--2019|Hoen et al. 2019]] ). Offshore wind farms projects have higher public support, but can also face resistance ( [[#Bidwell--2017|Bidwell 2017]] ; [[#Rudolph--2018|Rudolph et al. 2018]] ).

Common economic barriers to wind development are high initial cost of capital, long payback periods, and inadequate access to capital. Optimal wind energy expansion is most likely to occur in the presence of a political commitment to establish, maintain, and improve financial support instruments, technological efforts to support a local supply chains, and grid investments integrate VRE electricity ( [[#Diógenes--2020|Diógenes et al. 2020]] ).

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