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

=== Box 6.4 | Critical Strategic Minerals and a Low-carbon Energy System Transition ===

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The secure supply of many metals and minerals (e.g., cobalt, copper, lithium, and rare earth elements (REEs)) is critical to supporting a low-emissions energy system transition ( [[#Sovacool--2020|]] [[#Sovacool--2020|Sovacool et al. 2020]] ). A low-carbon energy system transition will increase the demand for these minerals to be used in technologies like wind turbines, PV cells, and batteries ( [[#World%20Bank--2020|World Bank 2020]] ). Reliance on these minerals has raised questions about possible constraints to a low-carbon energy system transition, including supply chain disruptions (Chapter 10.6). Concerns have also been raised about mining for these materials, which frequently results in severe environmental impacts ( [[#Sonter--2020|Sonter et al. 2020]] ), and metal production itself is energy-intensive and difficult to decarbonise ( [[#Sovacool--2020|]] [[#Sovacool--2020|Sovacool et al. 2020]] ).

Wind energy depends on two critical REEs – neodymium and dysprosium – used in magnets in high-performance generators ( [[#Pavel--2017|Pavel et al. 2017]] ; [[#Li--2020b|Li et al. 2020b]] ). Silicon-wafer-based solar PV, which accounted for 95% of PV production in 2020, does not use REEs but utilises aluminium, copper, and silver ( [[#IEA--2021a|IEA 2021a]] ). Lithium, nickel, cobalt, and phosphorous are used in batteries. Many critical minerals are used in EVs, including aluminium and copper in manufacturing the necessary EV charging infrastructure, and neodymium in permanent magnet motors.

These strategic minerals are found in a limited number of countries, and concerns have been raised that geopolitical factors could disrupt the supply chain necessary for a low-carbon energy system transition. However, excluding cobalt and lithium, no single country holds more than a third of the world reserves. The known supply of some strategic minerals is still close to 600 years at current levels of demand ( [[#BP--2020|BP 2020]] ), but increased demand would cut more quickly into supplies.

Box 6.4

There are alternatives to the strategic minerals currently used to support a low-carbon transition. Wind turbines can be manufactured without permanent magnets to reduce the need for strategic minerals, but the production costs are higher, and their efficiency is reduced ( [[#Månberger--2018|Månberger and Stenqvist 2018]] ). Alternatives to silicon, such as thin films, could be used to produce PVs. Thin-films use much less material than silicon-based PV, but they contain other potentially critical metals like tellurium, cadmium, and gallium. Alternatives to lithium-ion batteries, such as sodium-ion batteries, are becoming more practical and feasible ( [[#Sovacool--2020|]] [[#Sovacool--2020|Sovacool et al. 2020]] ).

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<span id="hydroelectric-power"></span>
==== 6.4.2.3 Hydroelectric Power ====

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Hydropower is technically mature, proved worldwide as a primary source of renewable electricity, and may be used to balance electricity supply by providing flexibility and storage. The LCOE of hydropower is lower than the cheapest new fossil fuel-fired option. However, the future mitigation potential of hydropower depends on minimising environmental and social impacts during the planning stages, reducing the risks of dam failures, and modernising the ageing hydropower fleet to increase generation capacity and flexibility ( ''high confidence'' ).

Estimates of global gross theoretical available hydropower potential varies from 31–128 PWh yr –1 (112–460 EJ yr –1 ), exceeding total electricity production in 2018 ( [[#Banerjee--2017|Banerjee et al. 2017]] ; [[#BP--2020|BP 2020]] ; [[#IEA--2021d|IEA 2021d]] ). This potential is distributed over 11.8 million locations (Figure 6.12), but many of the locations cannot be developed for (current) technical, economic, or political reasons. The estimated technical potential of hydropower is 8–30 PWh yr –1 (29–108 EJ yr –1 ), and its estimated economic potential is 8–15 PWh yr –1 (29–54 EJ yr –1 ) ( [[#Zhou--2015|Zhou et al. 2015]] ; [[#van%20Vliet--2016c|van Vliet et al. 2016c]] ). Actual hydropower generation in 2019 was 4.2 PWh (15.3 EJ), providing about 16% of global electricity and 43% of global electricity from renewables ( [[#BP--2020|BP 2020]] ; [[#IEA--2020f|IEA 2020f]] ; [[#Killingtveit--2020|Killingtveit 2020]] ). Asia holds the largest hydropower potential (48%), followed by South America (19%) ( [[#Hoes--2017|Hoes et al. 2017]] ).

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[[File:ecb735027f9e0293917943f24c6585a3 IPCC_AR6_WGIII_Figure_6_12.png]]

'''Figure 6.12 | Global map of gross hydropower potential distribution [GWh yr''' –1 '''].''' Source: data from Hoeset al. (2017).

Hydropower is a mature technology with locally adapted solutions ( ''high confidence'' ) ( [[#Zhou--2015|Zhou et al. 2015]] ; [[#Killingtveit--2020|Killingtveit 2020]] ). The peak efficiency of hydroelectric plants is greater than 85%. Hydropower plants without storage or with small storage typically produce a few kWs to 10 MWs (examples of plants producing higher amounts do exist), and are useful for providing electricity at a scale from households to small communities ( [[#El%20Bassam--2013|El Bassam et al. 2013]] ; [[#Towler--2014|Towler 2014]] ). However, hydropower plants without or with small storage may be susceptible to climate variability, especially droughts, when the amount of water may not be sufficient to generate electricity ( [[#Premalatha--2014|Premalatha et al. 2014]] ) ( [[#6.5|Section 6.5]] ).

Hydropower plants with storage may produce 10 GW, reaching over 100 TWh yr –1 (0.36 EJ yr –1 ), but generally require large areas. Pumped storage hydropower stores energy by pumping water to higher reservoirs during low-demand periods ( [[#Killingtveit--2020|Killingtveit 2020]] ). The storage in hydropower systems provides flexibility to compensate for rapid variations in electricity loads and supplies. The regulating characteristics of the storage play an important role in assuring continuity of energy supply from renewable sources ( [[#Yang--2018b|Yang et al. 2018b]] ).

Hydropower is one of the lowest-cost electricity technologies ( [[#Mukheibir--2013|Mukheibir 2013]] ; [[#IRENA--2021b|IRENA 2021b]] ). Its operation and maintenance costs are typically 2–2.5% of the investment costs per kW yr –1 for a lifetime of 40–80 years ( [[#Killingtveit--2020|Killingtveit 2020]] ). Construction costs are site-specific. The total cost for an installed large hydropower project varies from USD10,600–804,500 kW –1 if the site is located far away from transmission lines, roads, and infrastructure. Investment costs increase for small hydropower plants and may be as high as USD100,000 kW –1 or more for the installation of plants of less than 1 MW – 20% to 80% more than for large hydropower plants ( [[#IRENA--2015|IRENA 2015]] ). During the past 100 years, total installed costs and LCOE have risen by a few percent, but the LCOE of hydropower remains lower than the cheapest new fossil fuel-fired option ( [[#IRENA--2019b|IRENA 2019b]] , 2021).

Hydroelectric power plants may pose serious environmental and societal impacts ( ''high confidence'' ) ( [[#McCartney--2009|McCartney 2009]] ). Dams may lead to fragmentation of ecological habitats because they act as barriers for migration of fish and other land and water-borne fauna, sediments, and water flow. These barriers can be mitigated by sediment passes and fish migration aids, and with provision of environmental flows. Below dams, there can be considerable alterations to vegetation, natural river flows, retention of sediments and nutrients, and water quality and temperature. Construction of large reservoirs leads to loss of land, which may result in social and environmental consequences. Minimising societal and environmental impacts requires taking into account local physical, environmental, climatological, social, economic, and political aspects during the planning stage ( [[#Killingtveit--2020|Killingtveit 2020]] ). Moreover, when large areas of land are flooded by dam construction, they generate GHGs ( [[#Prairie--2018|Prairie et al. 2018]] ; [[#Phyoe--2019|Phyoe and Wang 2019]] ; [[#Maavara--2020|Maavara et al. 2020]] ). On the other hand, hydropower provides flexible, competitive low-emission electricity, local economic benefits (e.g., by increasing irrigation and electricity production in developing countries), and ancillary services such as municipal water supply, irrigation and drought management, navigation and recreation, and flood control ( [[#IRENA--2021b|IRENA 2021b]] ). However, the long-term economic benefits to communities affected by reservoirs are a subject of debate ( [[#de%20Faria--2017|de Faria et al. 2017]] ; [[#Catolico--2021|Catolico et al. 2021]] ).

Public support for hydroelectric energy is generally high ( [[#Steg--2018|Steg 2018]] ), and higher than support for coal, gas, and nuclear. Yet, public support for hydro seems to differ for existing and new projects ( ''high confidence'' ). Public support is generally high for small- and medium-scale hydropower in regions where hydropower was historically used ( [[#Gormally--2014|Gormally et al. 2014]] ). Additionally, there is high support for existing large hydropower projects in Switzerland ( [[#Rudolf--2014|Rudolf et al. 2014]] ; [[#Plum--2019|Plum et al. 2019]] ), Canada ( [[#Boyd--2019|Boyd et al. 2019]] ), and Norway ( [[#Karlstrøm--2014|Karlstrøm and Ryghaug 2014]] ), where it is a trusted and common energy source. Public support seems lower for new hydropower projects ( [[#Hazboun--2020|Hazboun and Boudet 2020]] ), and the construction of new large hydropower plants has been met with strong resistance in some areas ( [[#Vince--2010|Vince 2010]] ; [[#Bronfman--2015|Bronfman et al. 2015]] ). People generally perceive hydroelectric energy as clean and a non-contributor to climate change and environmental pollution ( [[#Kaldellis--2013|Kaldellis et al. 2013]] ). For example, in Sweden, people believed that existing hydropower projects have as few negative environmental impacts as solar, and even less than wind ( [[#Ek--2005|Ek 2005]] ). However, in areas where the construction of new large-scale hydroelectric energy is met with resistance, people believe that electricity generation from hydro can cause environmental, social, and personal risks ( [[#Bronfman--2012|Bronfman et al. 2012]] ; [[#Kaldellis--2013|Kaldellis et al. 2013]] ).

The construction time of hydroelectric power plants is longer than many other renewable technologies, and that construction time may be extended by the additional time it takes to fill the reservoir. This extended timeline can create uncertainty in the completion of the project. The uncertainty is due to insecurity in year-to-year variations in precipitation and the water inflows required to fill reservoirs. This is especially critical in the case of trans-boundary hydroelectric power plants, where filling up the reservoirs can have large implications on downstream users in other nations. As a result of social and environmental constraints, only a small fraction of potential economic hydropower projects can be developed, especially in developed countries. Many developing countries have major undeveloped hydropower potential, and there are opportunities to develop hydropower combined with other economic activities such as irrigation ( [[#Lacombe--2014|Lacombe et al. 2014]] ). Competition for hydropower across country borders can lead to conflict, which could be exacerbated if climate alters rainfall and streamflow ( [[#Ito--2016|Ito et al. 2016]] ).

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<span id="nuclear-energy"></span>
==== 6.4.2.4 Nuclear Energy ====

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Nuclear power can deliver low-carbon energy at scale ( ''high confidence'' ). Doing so will require improvements in managing construction of reactor designs that hold the promise of lower costs and broader use ( ''medium confidence'' ). At the same time, nuclear power continues to be affected by cost overruns, high upfront investment needs, challenges with final disposal of radioactive waste, and varying public acceptance and political support levels ( ''high confidence'' ).

There are sufficient resources for substantially increasing nuclear deployment ( ''medium confidence'' ). Estimates for identified uranium resources have been increasing steadily over the years. Conventional uranium resources have been estimated to be sufficient for over 130 years of supply at current levels of use; 100 years were estimated in 2009 ( [[#Hahn--1983|Hahn 1983]] ; [[#NEA/IAEA--2021|NEA/IAEA 2021]] ). In the case of future uranium resource scarcity, thorium or recycling of spent fuel might be used as alternatives. Interest in these alternatives has waned with better understanding of uranium deposits, their availability, and low prices ( [[#IAEA--2005|IAEA 2005]] ; OECD NEA 2015).

There are several possible nuclear technology options for the period from 2030 to 2050 ( ''medium confidence'' ). In addition to electricity, nuclear can also be used to produce low-carbon hydrogen and freshwater ( [[#Kavvadias--2014|Kavvadias and Khamis 2014]] ; [[#Kayfeci--2019|Kayfeci et al. 2019]] ).

• '''Large reactors.''' The nuclear industry has entered a new phase of reactor construction, based on evolutionary designs. These reactors achieve improvements over previous designs through small to moderate modifications, including improved redundancy, increased application of passive safety features, and significant improvements to containment design to reduce the risk of a major accident ( [[#MIT--2018|MIT 2018]] ). Examples include European – EPR, Korean – APR1400, USA – AP1000, Chinese – HPR1000 or Russian – VVER-1200.

'''•''' '''Long-term operation (LTO) of the current fleet.''' Continued production from nuclear power will depend in part on life extensions of the existing fleet. By the end of 2020, two-thirds of nuclear power reactors will have been operational for over 30 years. The design lifetime of most of existing reactors is 30–40 years. Engineering assessments have established that reactors can operate safely for longer if key replaceable components (e.g., steam generator, mechanical and electrical equipment, instrumentation and control parts) are changed or refurbished ( [[#IAEA--2018|IAEA 2018]] ). The first lifetime extension considered in most of the countries typically is 10–20 years ( [[#IEA--2020j|IEA 2020j]] ).

• '''Small modular reactors (SMR).''' There are more than 70 SMR designs at different stages of consideration and development, from the conceptual phase to licensing and construction of first-of-a-kind facilities ( [[#IAEA--2020|IAEA 2020]] ). Due to smaller unit sizes, the SMRs are expected to have lower total investment costs, although the cost per unit of generation might be higher than conventional large reactors ( [[#Mignacca--2020|Mignacca and Locatelli 2020]] ). Modularity and off-site pre-production may allow greater efficiency in construction, shorter delivery times, and overall cost optimisation ( [[#IEA--2019c|IEA 2019c]] ). SMR designs aim to offer an increased load-following capability that makes them suitable to operate in smaller systems and in systems with increasing shares of VRE sources. Their market development by the early 2030s will strongly depend on the successful deployment of prototypes during the 2020s.

Nuclear power costs vary substantially across countries ( ''high confidence'' ). First-of-a-kind projects under construction in Northern America and Europe have been marked by delays and costs overruns ( [[#Berthelemy--2015|Berthelemy and Rangel 2015]] ). Construction times have exceeded 13–15 years and cost has surpassed three to four times initial budget estimates ( [[#IEA--2020j|IEA 2020j]] ). In contrast, most of the recent projects in Eastern Asia (with construction starts from 2012) were implemented within five to six years (IAEA 2021). In addition to region-specific factors, future nuclear costs will depend on the ability to benefit from the accumulated experience in controlling the main drivers of cost. These cost drivers fall into four categories: design maturity; project management; regulatory stability and predictability; and multi-unit and series effects ( [[#NEA--2020|NEA 2020]] ). With lessons learned from first-of-a-kind projects, the cost of electricity for new builds are expected to be in the range of USD42–102 MWh –1 depending on the region ( [[#IEA--2020j|IEA 2020j]] ).

Lifetime extensions are significantly cheaper than new builds and cost competitive with other low-carbon technologies. The overnight cost of lifetime extensions is estimated in the range of USD390–630 kWe –1 for Europe and North America, and the LCOE in the range of USD30–36 MWh –1 for extensions of 10–20 years ( [[#IEA--2020j|IEA 2020j]] ).

Cost-cutting opportunities, such as design standardisation and innovations in construction approaches, are expected to make SMRs competitive against large reactors by 2040 ( [[#Rubio--2016|Rubio and Tricot 2016]] ) ( ''medium confidence'' ). As SMRs are under development, there is substantial uncertainty regarding the construction costs. Vendors have estimated first-of-a-kind LCOEs at USD131–190 MWh –1 . Effects of learning for nth-of-a-kind SMR are anticipated to reduce the first-of-a-kind LCOE by 19–32%.

Despite low probabilities, the potential for major nuclear accidents exists, and the radiation exposure impacts could be large and long-lasting ( [[#Steinhauser--2014|Steinhauser et al. 2014]] ). However, new reactor designs with passive and enhanced safety systems reduce the risk of such accidents significantly ( ''high confidence'' ). The (normal) activity of a nuclear reactor results in low volumes of radioactive waste, which requires strictly controlled and regulated disposal. On a global scale, roughly 421 kt of spent nuclear fuel have been produced since 1971 (IEA 2014). Out of this volume, 2–3% is high-level radioactive waste, which presents challenges in terms of radiotoxicity and decay longevity, and ultimately entails permanent disposal.

Nuclear energy is found to be favourable regarding land occupation ( [[#Cheng--2017|Cheng and Hammond 2017]] ; [[#Luderer--2019|Luderer et al. 2019]] ) and ecological impacts ( [[#Brook--2015|Brook and Bradshaw 2015]] ; [[#Gibon--2017|Gibon et al. 2017]] ). Similarly, bulk material requirements per unit of energy produced are low (e.g., aluminum, copper, iron, rare earth metals) ( [[#Vidal--2013|Vidal et al. 2013]] ; [[#Luderer--2019|Luderer et al. 2019]] ). Water-intensive inland nuclear power plants may contribute to localised water stress and competition for water uses. The choice of cooling systems (closed-loop instead of once-through) can significantly moderate withdrawal rates of freshwater ( [[#Meldrum--2013|Meldrum et al. 2013]] ; [[#Fricko--2016|Fricko et al. 2016]] ; [[#Mouratiadou--2016|Mouratiadou et al. 2016]] ; [[#Jin--2019|Jin et al. 2019]] ). Reactors situated on the seashore are not affected by water scarcity issues ( [[#Abousahl--2021|Abousahl et al. 2021]] ). Lifecycle analysis (LCA) studies suggest that the overall impacts on human health (in terms of disability adjusted life years (DALYs)) from the normal operation of nuclear power plants are substantially lower than those caused by fossil fuel technologies and are comparable to renewable energy sources ( [[#Treyer--2014|Treyer et al. 2014]] ; [[#Gibon--2017|Gibon et al. 2017]] ).

Nuclear power continues to suffer from limited public and political support in some countries ( ''high confidence'' ). Public support for nuclear energy is consistently lower than for renewable energy and natural gas, and in many countries as low as support for energy from coal and oil ( [[#Corner--2011|Corner et al. 2011]] ; [[#Pampel--2011|Pampel 2011]] ; [[#Hobman--2013|Hobman and Ashworth 2013]] ). The major nuclear accidents (i.e., Three Mile Island, Chernobyl, and Fukushima) decreased public support ( [[#Poortinga--2013|Poortinga et al. 2013]] ; [[#Bird--2014|Bird et al. 2014]] ). The public remains concerned about the safety risks of nuclear power plants and radioactive materials ( [[#Pampel--2011|Pampel 2011]] ; [[#Bird--2014|Bird et al. 2014]] ; [[#Tsujikawa--2016|Tsujikawa et al. 2016]] ). At the same time, some groups see nuclear energy as a reliable energy source, beneficial for the economy and helpful in climate change mitigation. Public support for nuclear energy is higher when people are concerned about energy security, including concerns about the availability of energy and high energy prices (Groot et al. 2013; [[#Gupta--2019b|Gupta et al. 2019b]] ), and when they expect local benefit ( [[#Wang--2020c|Wang et al. 2020c]] ). Public support also increases when trust in managing bodies is higher ( [[#de%20Groot--2011|de Groot and Steg 2011]] ). Similarly, transparent and participative decision-making processes enhance perceived procedural fairness and public support ( [[#Sjoberg--2004|Sjoberg 2004]] ).

Because of the sheer scale of the investment required (individual projects can exceed USD10 billion in value), nearly 90% of nuclear power plants under construction are run by state-owned or controlled companies, with governments assuming significant part of the risks and costs. For countries that choose nuclear power in their energy portfolio, stable political conditions and support, clear regulatory regimes, and adequate financial framework are crucial for successful and efficient implementation.

Many countries have adopted technology-specific policies for low-carbon energy courses, and these policies influence the competitiveness of nuclear power. For example, feed-in-tariffs and feed-in premiums for renewables widely applied in the EU ( [[#Kitzing--2012|Kitzing et al. 2012]] ) or renewable portfolio standards in the USA ( [[#Barbose--2016|Barbose et al. 2016]] ) impact wholesale electricity price (leading occasionally to low or even negative prices), which affects the revenues of existing nuclear and other plants ( [[#Bruninx--2013|Bruninx et al. 2013]] ; [[#Newbery--2018|Newbery et al. 2018]] ; [[#Lesser--2019|Lesser 2019]] ).

Nuclear power’s long-term viability may hinge on demonstrating to the public and investors that there is a long-term solution to spent nuclear fuel. Evidence from countries steadily progressing towards first final disposals – Finland, Sweden and France – suggests that broad political support, coherent nuclear waste policies, and a well-managed, consensus-based decision-making process are critical for accelerating this process ( [[#Metlay--2016|Metlay 2016]] ). Proliferation concerns surrounding nuclear power are related to fuel cycle (i.e., uranium enrichment and spent fuel processing). These processes are implemented in a very limited number of countries following strict national and internationals norms and rules, such as the International Atomic Energy Agency (IAEA) guidelines, treaties and conventions. Most of the countries that might introduce nuclear power in the future for their climate change mitigation benefits do not envision developing their own full fuel cycle, significantly reducing any risks that might be linked to proliferation ( [[#IAEA--2014|IAEA 2014]] , 2019).

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<span id="carbon-dioxide-capture-utilisation-and-storage"></span>
==== 6.4.2.5 Carbon Dioxide Capture, Utilisation and Storage ====

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Since AR5, there have been increased efforts to develop novel platforms that reduce the energy penalty associated with CO 2 capture, develop CO 2 utilisation pathways as a substitute to geologic storage, and establish global policies to support CCS ( ''high confidence'' ). CCS can be used within electricity and other sectors. While it increases the cost of electricity, CCS has the potential to contribute significantly to low-carbon energy system transitions ( [[#IPCC--2018|IPCC 2018]] ).

The theoretical global geologic storage potential is about 10,000 GtCO 2 , with more than 80% of this capacity existing in saline aquifers ( ''medium confidence'' ). Not all the storage capacity is usable because geologic and engineering factors limit the actual storage capacity to an order of magnitude below the theoretical potential, which is still more than the CO 2 storage requirement through 2100 to limit temperature change to 1.5°C ( [[#Martin-Roberts--2021|Martin-Roberts et al. 2021]] ) ( ''high confidence'' ). One of the key limiting factors associated with geologic CO 2 storage is the global distribution of storage capacity (Table 6.2). Most of the available storage capacity exists in saline aquifers. Capacity in oil and gas reservoirs and coalbed methane fields is limited. Storage potential in the USA alone is &gt;1000 GtCO 2 , which is more than 10% of the world total ( [[#NETL--2015|NETL 2015]] ). The Middle East has more than 50% of global enhanced oil recovery potential ( [[#Selosse--2017|Selosse and Ricci 2017]] ). It is likely that oil and gas reservoirs will be developed as geologic sinks before saline aquifers because of existing infrastructure and extensive subsurface data ( [[#Alcalde--2019|Alcalde et al. 2019]] ; [[#Hastings--2020|Hastings and Smith 2020]] ). Notably, not all geologic storage is utilisable. In places with limited geologic storage, international CCS chains are being considered, where sources and sinks of CO 2 are located in two or more countries ( [[#Sharma--2021|Sharma and Xu 2021]] ). For economic long-term storage, the desirable conditions are a depth of 800–3000 m, thickness of greater than 50 m and permeability greater than 500 mD ( [[#Chadwick--2008|Chadwick et al. 2008]] ; [[#Singh--2021|Singh et al. 2021]] ). Even in reservoirs with large storage potential, the rate of injection might be limited by the subsurface pressure of the reservoir ( [[#Baik--2018|Baik et al. 2018]] ). It is estimated that geologic sequestration is reliable with overall leakage rates at &lt;0.001% yr –1 ( [[#Alcalde--2018|Alcalde et al. 2018]] ). In many cases, geological storage resources are not located close to CO 2 sources, increasing costs and reducing viability ( [[#Garg--2017a|Garg et al. 2017a]] ).

'''Table 6.2 | Geologic storage potential across underground formations globally.''' '''These represent order-of-magnitude estimates.''' Data: Selosseand Ricci (2017).

{| class="wikitable"
|-
| '''Reservoir typ''' e

| '''Africa'''

| '''Australia'''

| '''Canada'''

| '''China'''

| '''CSA'''

| '''EEU'''

| '''FSU'''

| '''India'''

| '''MEA'''

| '''Mexico'''

| '''ODA'''

| '''USA'''

| '''WEU'''

|-
| Enhanced oil recovery

| 3

| 0

| 3

| 1

| 8

| 2

| 15

| 0

| 38

| 0

| 1

| 8

| 0

|-
| Depleted oil and gas fields

| 20

| 8

| 19

| 1

| 33

| 2

| 191

| 0

| 252

| 22

| 47

| 32

| 37

|-
| Enhanced coalbed methane recovery

| 8

| 30

| 16

| 16

| 0

| 2

| 26

| 8

| 0

| 0

| 24

| 90

| 12

|-
| Deep saline aquifers

| 1000

| 500

| 667

| 500

| 1000

| 250

| 1000

| 500

| 500

| 250

| 1015

| 1000

| 250

|}

CSA: Central and South America, EEU: Eastern Europe, FSU: Former Soviet Union, MEA: Middle East, ODA: Other Asia (except China and India), WEU: Western Europe.

CO 2 utilisation (CCU) – instead of geologic storage – could present an alternative method of decarbonisation ( ''high confidence'' ). The global CO 2 utilisation potential, however, is currently limited to 1–2 GtCO 2 yr –1 for use of CO 2 as a feedstock ( [[#Hepburn--2019|Hepburn et al. 2019]] ; [[#Kätelhön--2019|Kätelhön et al. 2019]] ) but could increase to 20 GtCO 2 by the mid-century ( ''medium confidence'' ). CCU involves using CO 2 as a feedstock to synthesise products of economic value and as substitute to fossil feedstock. However, several CO 2 utilisation avenues might be limited by energy availability. Depending on the utilisation pathway, the CO 2 may be considered sequestered for centuries (e.g., cement curing, aggregates), decades (plastics), or only a few days or months (e.g., fuels) ( [[#Hepburn--2019|Hepburn et al. 2019]] ). Moreover, when carbon-rich fuel end-products are combusted, CO 2 is emitted back into the atmosphere. Because of the presence of several industrial clusters (regions with high density of industrial infrastructure) globally, a number of regions demonstrate locations where CO 2 utilisation potential could be matched with large point sources of CO 2 ( [[#Wei--2020|Wei et al. 2020]] ).

The technological development for several CO 2 utilisation pathways is still in the laboratory, prototype, and pilot phases, while others have been fully commercialised (such as urea manufacturing). Technology development in some end uses is limited by purity requirements for CO 2 as a feedstock. The efficacy of CCU processes depends on additional technological constraints such as CO 2 purity and pressure requirements. For instance, urea production requires CO 2 pressurised to 122 bar and purified to 99.9%. While most utilisation pathways require purity levels of 95–99%, algae production may be carried out with atmospheric CO 2 ( [[#Voldsund--2016|Voldsund et al. 2016]] ; [[#Ho--2019|Ho et al. 2019]] ).

Existing post-combustion approaches relying on absorption are technologically ready for full-scale deployment ( ''high confidence'' ). More novel approaches using membranes and chemical looping that might reduce the energy penalty associated with absorption are in different stages of development – ranging from laboratory phase to prototype phase ( [[#Abanades--2015|Abanades et al. 2015]] ) ( ''high confidence'' ). There has been significant progress in post-combustion capture technologies that used absorption in solvents such as monoethanolamine (MEA). There are commercial-scale application of solvent-based absorption at two electricity generating facilities – Boundary Dam since 2015 and Petra Nova (temporarily suspended) since 2017, with capacities of 1 and 1.6 MtCO 2 yr –1 respectively ( [[#Mantripragada--2019|Mantripragada et al. 2019]] ; [[#Giannaris--2020|Giannaris et al. 2020]] a). Several second- and third-generation capture technologies are being developed with the aim of not just lowering costs but also enhancing other performance characteristics such as improved ramp-up and lower water consumption. These include processes such as chemical looping, which also has the advantage of being capable of co-firing with biomass with a better efficiency ( [[#Bhave--2017|Bhave et al. 2017]] ; [[#Yang--2019|Yang et al. 2019]] ). Another important technological development is the Allam cycle, which utilises CO 2 as a working fluid and operates based on oxy-combustion capture. Applications using the Allam Cycle can deliver net energy efficiency greater than 50% and nearly 100% CO 2 capture, but they are quite sensitive to oxygen and CO 2 purity needs ( [[#Scaccabarozzi--2016|Scaccabarozzi et al. 2016]] ; [[#Ferrari--2017|Ferrari et al. 2017]] ).

CO 2 capture costs present a key challenge, remaining higher than USD50 tCO 2 –1 for most technologies and regions; novel technologies could help reduce some costs ( ''high confidence'' ). The capital cost of a coal or gas electricity generation facility with CCS is almost double that of one without CCS ( [[#Rubin--2015|Rubin et al. 2015]] ; [[#Zhai--2016|Zhai and Rubin 2016]] ; [[#Bui--2018|Bui et al. 2018]] ). Additionally, the energy penalty increases the fuel requirement for electricity generation by 13–44%, leading to further cost increases (Table 6.3).

'''Table 6.3| Costs and efficiency parameters of CCS in electric power plants.''' Data: [[#Muratori--2017a|Muratori et al. (2017a)]] '''.'''

{| class="wikitable"
|-
|
| Capital cost [USD kW –1 ]

| Efficiency [%]

| CO 2 capture cost [USD tCO 2 –1 ]

| CO 2 avoided cost [USD tCO 2 –1 ]

|-
| Coal (steam plant) + CCS

| 5800

| 28%

| 63

| 88

|-
| Coal (IGCC) + CCS

| 6600

| 32%

| 61

| 106

|-
| Natural gas (CC) + CCS

| 2100

| 42%

| 91

| 33

|-
| Oil (CC) + CCS

| 2600

| 39%

| 105

| 95

|-
| Biomass (steam plant) + CCS

| 7700

| 18%

| 72

| 244

|-
| Biomass (IGCC) + CCS

| 8850

| 25%

| 66

| 242

|}

In addition to reductions in capture costs, other approaches to reduce CCS costs rely on utilising the revenues from co-products such as oil, gas, or methanol, and on clustering of large-point sources to reduce infrastructure costs. The potential for such reductions is limited in several regions due to low sink availability, but it could jump-start initial investments ( ''medium confidence'' ). Injecting CO 2 into hydrocarbon formations for enhanced oil or gas recovery can produce revenues and lower costs ( [[#Edwards--2018|Edwards and Celia 2018]] ). While enhanced oil recovery potential is &lt;5% of the actual CCS needs, they can enable early pilot and demonstration projects ( [[#Núñez-López--2019|Núñez-López and Moskal 2019]] ; [[#Núñez-López--2019|Núñez-López et al. 2019]] ). Substantial portions of CO 2 are effectively stored during enhanced oil recovery ( [[#Menefee--2020|Menefee and Ellis 2020]] ; [[#Sminchak--2020|Sminchak et al. 2020]] ). By clustering together of several CO 2 sources, overall costs may be reduced by USD10 tCO 2 –1 ( [[#Abotalib--2016|Abotalib et al. 2016]] ; [[#Garg--2017a|Garg et al. 2017a]] ), but geographical circumstances determine the prospects of these cost reductions via economies of scale. The major pathways for CO 2 utilisation via methanol, methane, liquid fuel production, and cement curing have costs greater than USD500 tCO 2 –1 ( [[#Hepburn--2019|Hepburn et al. 2019]] ). The success of these pathways therefore depends on the value of such fuels and on the values of other alternatives.

The public is largely unfamiliar with carbon capture, use and storage technologies ( [[#L’Orange%20Seigo--2014|L’Orange Seigo et al. 2014]] ; [[#Tcvetkov--2019|Tcvetkov et al. 2019]] ) ( ''high confidence'' ), and many people may not have formed stable attitudes and risk perceptions regarding these technologies ( [[#Daamen--2006|Daamen et al. 2006]] ; [[#Jones--2015|Jones et al. 2015]] ; [[#Van%20Heek--2017|Van Heek et al. 2017]] ) ( ''medium confidence'' ). In general, low support has been reported for CCS technologies ( [[#Allen--2013|Allen and Chatterton 2013]] ; [[#Demski--2017|Demski et al. 2017]] ). When presented with neutral information on CCS, people favour other mitigation options such as renewable energy and energy efficiency (de Best-Waldhober et al. 2009; [[#Scheer--2013|Scheer et al. 2013]] ; [[#Karlstrøm--2014|Karlstrøm and Ryghaug 2014]] ). Although few totally reject CCS, specific CCS projects have faced strong local resistance, which has contributed to the cancellation of CCS projects ( [[#Terwel--2012|Terwel et al. 2012]] ; [[#L’Orange%20Seigo--2014|L’Orange Seigo et al. 2014]] ). Communities may also consider CCU to be lower-risk and view it more favourably than CCS ( [[#Arning--2019|Arning et al. 2019]] ).

CCS requires considerable increases in some resources and chemicals, most notably water. Power plants with CCS could shut down periodically due to water scarcity. In several cases, water withdrawals for CCS are 25–200% higher than plants without CCS ( [[#Rosa--2020b|Rosa et al. 2020b]] ; [[#Yang--2020|Yang et al. 2020]] ) due to energy penalty and cooling duty. The increase is slightly lower for non-absorption technologies. In regions prone to water scarcity such as the Southwestern USA or Southeast Asia, this may limit deployment and result in power plant shutdowns during the summer months ( [[#Liu--2019b|Liu et al. 2019b]] ; [[#Wang--2019c|Wang et al. 2019c]] ). The water use could be managed by changing heat integration strategies and implementing reuse of wastewater ( [[#Magneschi--2017|Magneschi et al. 2017]] ; [[#Giannaris--2020|Giannaris et al. 2020]] b).

Because CCS always adds cost, policy instruments are required for it to be widely deployed ( ''high confidence'' ). Relevant policy instruments include financial instruments such as emission certification and trading, legally enforced emission restraints, and carbon pricing ( [[#Haszeldine--2016|Haszeldine 2016]] ; [[#Kang--2020|Kang et al. 2020]] ). There are some recent examples of policy instruments specifically focused on promoting CCS. The recent 45Q tax credits in the USA offer nationwide tax credits for CO 2 capture projects above USD35–50 tCO 2 –1 which offset CO 2 capture costs at some efficient plants ( [[#Esposito--2019|Esposito et al. 2019]] ). Similarly, California’s low-carbon fuel standard offers benefits for CO 2 capture at some industrial facilities such as biorefineries and refineries ( [[#Von%20Wald--2020|Von Wald et al. 2020]] ).

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<span id="bioenergy"></span>
==== 6.4.2.6 Bioenergy ====

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Bioenergy has the potential to be a high-value and large-scale mitigation option to support many different parts of the energy system. Bioenergy could be particularly valuable for sectors with limited alternatives to fossil fuels (e.g., aviation, heavy industry), production of chemicals and products, and, potentially, in carbon dioxide removal (CDR) via BECCS or biochar. While traditional biomass and first-generation biofuels are widely used today, the technology for large-scale production from advanced processes is not competitive, and growing dedicated bioenergy crops raises a broad set of sustainability concerns. Its long-term role in low-carbon energy systems is therefore uncertain ( ''high confidence'' ). (Note that this section focuses on the key technological developments for deployment of commercial bioenergy.)

Bioenergy is versatile: technology pathways exist to produce multiple energy carriers from biomass – electricity, liquid fuels, gaseous fuels, hydrogen, and solid fuels – as well as other value-added products ( ''high confidence'' ). Different chemical and biological conversion pathways exist to convert diverse biomass feedstocks into multiple final energy carriers (Figure 6.14). Currently, biomass is mostly used to produce heat, or for cooking purposes (traditional biomass), electricity, or first-generation sugar-based biofuels (e.g., ethanol produced via fermentation), as well as biodiesel produced from vegetable oils and animal fats. Electricity generated from biomass contributes about 3% of global generation. Tens of billions of gallons of first-generation biofuels are produced per year. The processing requirements (drying, dewatering, pelletising) of different feedstocks for producing electricity from biomass are energy-intensive, and when utilising current power plants, the efficiency is around 22%, with an increase up to 28% with advanced technologies ( [[#Zhang--2020|Zhang et al. 2020]] ).

Scaling up bioenergy use will require advanced technologies such as gasification, Fischer-Tropsch processing, hydrothermal liquefaction (HTL), and pyrolysis. These pathways could deliver several final energy carriers starting from multiple feedstocks, including forest biomass, dedicated cellulosic feedstocks, crop residues, and wastes (Figure 6.14). While potentially cost-competitive in the future, pyrolysis, Fischer-Tropsch, and HTL are not currently cost-competitive ( [[#IEA--2018c|IEA 2018c]] ; [[#Molino--2018|Molino et al. 2018]] ; [[#Prussi--2019|Prussi et al. 2019]] ), and scaling-up these processes will require robust business strategies and optimised use of co-products ( [[#Lee--2013|Lee and Lavoie 2013]] ). Advanced biofuels production processes are at the pilot or demonstration stage and will require substantial breakthroughs or market changes to become competitive. Moreover, fuels produced from these processes require upgrading to reach ‘drop-in’ conditions – that is, conditions in which they may be used directly consistent with current standards in existing technologies ( [[#van%20Dyk--2019|van Dyk et al. 2019]] ). Additional opportunities exist to co-optimise second-generation biofuels and engines ( [[#Ostadi--2019|Ostadi et al. 2019]] ; [[#Salman--2020|Salman et al. 2020]] ). In addition, gaseous wastes, or high-moisture biomass, such as dairy manure, wastewater sludge and organic municipal solid waste (MSW) could be utilised to produce renewable natural gas. Technologies for producing biogas (e.g., digestion) tend to be less efficient than thermochemical approaches and often produce large amounts of CO 2 , requiring the produced fuels to undergo significant upgrading ( [[#Melara--2020|Melara et al. 2020]] ).

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[[File:c08ff1ffe65209ee327ad1e6315ceae6 IPCC_AR6_WGIII_Figure_6_13.png]]

'''Figure 6.13 | Costs and potential for different CO''' 2 '''utilisation pathways.''' Source: with permission from [[#Hepburn--2019|Hepburn et al. (2019)]] .

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[[File:31b2a571018212806f9a750b7b4413c6 IPCC_AR6_WGIII_Figure_6_14.png]]

'''Figure 6.14 | Range of advanced bioenergy conversion pathways (excluding traditional biomass, direct heat generation, first-generation biofuels, and non-energy products) based on feedstock, targeted end product, and compatibility with carbon dioxide removal (CDR) via carbon capture and storage (CCS) and soil carbon sequestration.''' Source: modified with permission from [[#Baker--2020|Baker et al. (2020)]] .

A major scale-up of bioenergy production will require dedicated production of advanced biofuels. First-generation biofuels produced directly from food crops or animal fats have limited potential and lower yield per land area than advanced biofuels. Wastes and residues (e.g., from agricultural, forestry, animal manure processing) or biomass grown on degraded, surplus, and marginal land can provide opportunities for cost-effective and sustainable bioenergy at significant but limited scale ( [[#Morris--2013|Morris et al. 2013]] ; [[#Saha--2018|Saha and Eckelman 2018]] ; [[#Fajardy--2020|Fajardy and Mac Dowell 2020]] ; [[#Spagnolo--2020|Spagnolo et al. 2020]] ). Assessing the potential for a major scale-up of purpose-grown bioenergy is challenging due to its far-reaching linkages to issues beyond the energy sector, including competition with land for food production and forestry, water use, impacts on ecosystems, and land-use change ( [[#IPCC--2020|IPCC 2020]] ; [[#Roe--2021|Roe et al. 2021]] ) (Chapter 12). These factors, rather than geophysical characteristics, largely define the potential for bioenergy and explain the difference in estimates of potential in the literature. Biomass resources are not always in close proximity to energy demand, necessitating additional infrastructure or means to transport biomass or final bioenergy over larger distances and incur additional energy use ( [[#Baik--2018|Baik et al. 2018]] ; [[#Singh--2021|Singh et al. 2021]] ).

An important feature of bioenergy is that it can be used to remove carbon from the atmosphere by capturing CO 2 in different parts of the conversion process and then permanently storing the CO 2 (BECCS or biochar) ( [[#Smith--2016|Smith et al. 2016]] ; [[#Fuss--2018|Fuss et al. 2018]] ) (Chapters 3 and 7, and [[IPCC:Wg3:Chapter:Chapter-12#12.5|Section 12.5]] ). Some early opportunities for low-cost BECCS are being utilised in the ethanol sector but these are applicable only in the near-term at the scale of ≤100 MtCO 2 yr –1 ( [[#Sanchez--2018|Sanchez et al. 2018]] ). Several technological and institutional barriers exist for large-scale BECCS implementation, including large energy requirements for CCS, limit and cost of biomass supply and geologic sinks for CO 2 in several regions, and cost of CO 2 capture technologies ( ''high confidence'' ). Besides BECCS, biofuels production through pyrolysis and hydrothermal liquefaction creates biochar, which could also be used to store carbon as 80% of the carbon sequestered in biochar will remain in the biochar permanently (Chapter 7). In addition to its ability to sequester carbon, biochar can be used as a soil amendment ( [[#Wang--2014b|Wang et al. 2014b]] ).

First-generation bioenergy is currently competitive in some markets though, on average, its costs are higher than other forms of final energy. Bioenergy from waste and residues from forestry and agriculture is also currently competitive, but the supply is limited ( [[#Aguilar--2020|Aguilar et al. 2020]] ). These costs are context-dependent, and regions having large waste resources are already producing low-cost bioenergy ( [[#Jin--2018|Jin and Sutherland 2018]] ). In the future, technology costs are anticipated to decrease, but bioenergy produced through cellulosic feedstocks may remain more expensive than fossil alternatives. Large-scale deployment of early opportunities, especially in the liquid fuel sector, may reduce the technological costs associated with biomass conversion ( [[#IEA--2020g|IEA 2020g]] ). At the same time, the cost of feedstocks may rise as bioenergy requirements increase, especially in scenarios with large bioenergy deployment (Muratori et al. 2020). The costs of bioenergy production pathways are highly uncertain (Table 6.4).

'''Table 6.4 | The costs of electricity generation, hydrogen production, and second-generation liquid fuels production from biomass in 2020.''' These costs are adapted from [[#Bhave--2017|Bhave et al. (2017)]] , Daioglou et al. (2020), NREL (2020a, 2020b), Witcover and Williams (2020), and Lepage et al. (2021).

{| class="wikitable"
|-
|
| Unit

| Low

| Median

| High

|-
| Bioelectricity with CCS

| USD MWh –1

| 74

| 86

| 160

|-
| Bioelectricity without CCS

| USD MWh –1

| 66

| 84

| 112

|-
| Biohydrogen with CCS a

| USD kg –1

| 1.63

| 2.37

| 2.41

|-
| Biohydrogen without CCS a

| USD kg –1

| 1.59

| 1.79

| 2.37

|-
| Liquid biofuels with CCS

| USD gge –1

| 1.34

| 4.20

| 7.85

|-
| Liquid biofuels without CCS

| USD gge –1

| 1.15

| 4.00

| 7.60

|}

a Using cellulosic feedstocks.

• '''Electricity.''' The costs of baseload electricity production with biomass are higher than corresponding fossil electricity production with and without CCS, and are likely to remain as such without carbon pricing ( [[#Bhave--2017|Bhave et al. 2017]] ). The additional cost associated with CO 2 capture are high for conventional solvent-based technologies. However, upcoming technologies such as chemical looping are well-suited to biomass and could reduce CCS costs.

'''•''' '''Hydrogen.''' The costs of hydrogen production from biomass are somewhat higher than, but comparable, to that produced by natural gas reforming with CCS. Further, the incremental costs for incorporating CCS in this process are less than 5% of the levelised costs in some cases, since the gasification route creates a high-purity stream of CO 2 ( [[#Muratori--2017a|Muratori et al. 2017a]] ; [[#Sunny--2020|Sunny et al. 2020]] ). While these processes have fewer ongoing prototypes/demonstrations, the costs of biomass-based hydrogen (with or without CCS) are substantially cheaper than that produced from electrolysis utilising solar/wind resources ( [[#Kayfeci--2019|Kayfeci et al. 2019]] ; [[#Newborough--2020|Newborough and Cooley 2020]] ), even though electrolysis costs are dropping.

• '''Liquid biofuels.''' First-generation sugar-based biofuels (e.g., ethanol produced via fermentation) or biodiesel produced from vegetable oils and animal fats, are produced in several countries at large scale and costs competitive with fossil fuels. However, supply is limited. The costs for second-generation processes (Fischer-Tropsch and cellulosic ethanol) are higher in most regions ( [[#Li--2019|Li et al. 2019]] ). Technological learning is projected to reduce these costs by half ( [[#IEA--2020g|IEA 2020g]] ).

Large-scale bioenergy production will require more than wastes/residues and cultivation on marginal lands, which may raise conflicts with SDGs relevant to environmental and societal priorities ( [[#Heck--2018|Heck et al. 2018]] ; [[#Gerten--2020|Gerten et al. 2020]] ) (Chapter 12). These include competition with food crops, implications for biodiversity, potential deforestation to support bioenergy crop production, energy security implications from bioenergy trade, point-of-use emissions and associated effects on air quality, and water use and fertiliser use ( [[#Fajardy--2018|Fajardy and Mac Dowell 2018]] ; [[#Fuss--2018|Fuss et al. 2018]] ; [[#Tanzer--2019|Tanzer and Ramírez 2019]] ; [[#Brack--2020|Brack and King 2020]] ). Overall, the environmental impact of bioenergy production at scale remains uncertain and varies by region and application.

Alleviating these issues would require some combination of increasing crop yields, improving conversion efficiencies, and developing advanced biotechnologies for increasing the fuel yield per tonne of feedstock ( [[#Henry--2018|Henry et al. 2018]] ). Policy structures would be necessary to retain biodiversity, manage water use, limit deforestation and land-use change emissions, and ultimately optimally integrate bioenergy with transforming ecosystems. Large-scale international trade of biomass might be required to support a global bioeconomy, raising questions about infrastructure, logistics, financing options, and global standards for bioenergy production and trade (Box 6.10). Additional institutional and economic barriers are associated with accounting of carbon dioxide removal, including BECCS ( [[#Fuss--2014|Fuss et al. 2014]] ; [[#Muratori--2016|Muratori et al. 2016]] ; [[#Fridahl--2018|Fridahl and Lehtveer 2018]] ).

Lifecycle emissions impacts from bioenergy are subject to large uncertainties and could be incompatible with net-zero emissions in some contexts. Due to the potentially large energy conversion requirements and associated GHG emissions (Chapters 7 and 12), bioenergy systems may fail to deliver near-zero emissions depending on operating conditions and regional contexts ( [[#Elshout--2015|Elshout et al. 2015]] ; [[#Daioglou--2017|Daioglou et al. 2017]] ; [[#Staples--2017|Staples et al. 2017]] ; [[#Hanssen--2020|Hanssen et al. 2020]] ; [[#Lade--2020|Lade et al. 2020]] ). As a result, bioenergy carbon neutrality is debated and depends on factors such as the source of biomass, conversion pathways and energy used for production and transport of biomass, and land-use changes, as well as assumed analysis boundary and considered time scale ( [[#Zanchi--2012|Zanchi et al. 2012]] ; [[#Wiloso--2016|Wiloso et al. 2016]] ; [[#Booth--2018|Booth 2018]] ; [[#Fan--2021|Fan et al. 2021]] ). Similarly, the lifecycle emissions of BECCS remain uncertain and will depend on how effectively bioenergy conversion processes are optimised ( [[#Fajardy--2017|Fajardy and Mac Dowell 2017]] ; [[#Tanzer--2019|Tanzer and Ramírez 2019]] ).

Acceptability of bioenergy is relatively low compared to other renewable energy sources like solar and wind ( [[#Poortinga--2013|Poortinga et al. 2013]] ; [[#Ma--2015|Ma et al. 2015]] ; [[#Peterson--2015|Peterson et al. 2015]] ; [[#EPCC--2017|EPCC 2017]] ) and comparable to natural gas ( [[#Scheer--2013|Scheer et al. 2013]] ). People also know relatively little about bioenergy compared to other energy sources ( [[#Whitmarsh--2011a|Whitmarsh et al. 2011a]] ; [[#EPCC--2017|EPCC 2017]] ) and tend be be more ambivalent towards bioenergy compared to other mitigation options ( [[#Allen--2013|Allen and Chatterton 2013]] ). People evaluate biomass from waste products (e.g., food waste) more favourably than grown-for-purpose energy crops, which are more controversial ( [[#Plate--2010|Plate et al. 2010]] ; [[#Demski--2015|Demski et al. 2015]] ). The most pressing concerns for use of woody biomass are air pollution and loss of local forests ( [[#Plate--2010|Plate et al. 2010]] ). Various types of bioenergy additionally raise concerns about landscape impacts ( [[#Whitmarsh--2011a|Whitmarsh et al. 2011a]] ) and biodiversity ( [[#Immerzeel--2014|Immerzeel et al. 2014]] ). Moreover, many people do not see biomass as a renewable energy source, possibly because it involves burning of material.

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