What is our assessment?

Advanced geothermal systems (AGS) are emerging as one of the most promising technologies for reliable, utility-scale, zero-carbon energy that can complement wind and solar, strengthening grid resilience, and providing heat for district heating and industrial uses. The technology, which is built on an existing base of technical and industrial expertise and capacity, is advancing rapidly through major R&D efforts, pilot projects and, just recently, small scale commercial operations. While large-scale deployment is still in its early stages and challenges remain around cost, execution, and social acceptance, we expect meaningful progress by the 2030s. For now, we will “Keep Watching” this solution.

What is it?

Advanced geothermal systems (AGS) are a suite of renewable energy technologies that extract heat from deep within the Earth’s crust to generate electricity, provide high-temperature heat for industrial processes or district heating, and enable geothermal energy storage by storing heat underground. Unlike traditional geothermal systems that tap naturally occurring hot water or steam reservoirs, such as geysers or volcanic areas, AGS access geothermal heat by drilling into the earth, injecting and circulating water (or other fluids) through hot, dry rock formations underground, and then recovering the heated fluid or steam to generate electricity before reinjecting it back underground. Circulation of the water between the surface and the geothermal reservoir can be a in closed loop system, where the water or other fluid is contained within pipes throughout the heat exchange circulation cycle, or in an open loop, enhanced geothermal system (EGS) where the subsurface rocks are hydraulically fractured, or “fracked,” to increase permeability and allow water to flow between an injection well and a production well.

Does it work?

Electricity and heat production by an advanced geothermal power plant emits virtually no greenhouse gases. Analysis by the National Renewable Energy Laboratory showed that the median life cycle emissions from enhanced geothermal power plants were 32 g CO₂‑eq/kWh, just 6% of the median life cycle emissions from a natural gas power plant, with most of the emissions generated during construction rather than operation. Geothermal energy has been used for more than a century, but AGS that use the directional and horizontal drilling and hydraulic fracturing techniques developed by the oil and gas industry to access previously inaccessible underground heat resources are relatively new. To date, several small-scale and experimental AGS projects have successfully produced electricity, and in December 2025, the first commercial plant for electricity and heat production delivered electricity to the grid in Germany. 

Why are we excited?

Advanced geothermal energy systems are a potentially transformative climate solution for several reasons. First, they could massively expand clean energy availability. AGS can be deployed in almost any region with hot subsurface rocks. Experts estimate the Earth’s accessible geothermal resources are staggeringly large, and that tapping just 0.1% of the heat under our feet could meet global energy needs for millennia. If technology improvements continue, advanced geothermal could supply around 15% of the world’s electricity by 2050. Second, unlike solar and wind energy, advanced geothermal power plants produce steady baseload power, dispatchable power, and even energy storage. Currently, coal and gas power plants are commonly used to provide stability and backup power to electricity grids around the world. AGS can provide the same energy benefits, complementing wind and solar energy by providing firm capacity and grid stability services to a renewable-heavy electricity grid, without the harmful climate impacts. Third, AGS plants have a relatively small land footprint and can potentially be sited near demand centers (including repurposing old fossil plant sites), improving energy security for regions with limited solar or wind resources.

Recent technological breakthroughs have improved the prospects for AGS. The application of directional drilling and hydraulic fracturing techniques has produced higher fluid flow rates and extended reservoir life. This has dramatically increased the heat extraction per well, overcoming previous limitations and boosting the energy output and economics of AGS. Industry reports show drilling rates in hot rock have increased by 300–500% in the last few years, slashing upfront costs. A recent U.S. Department of Energy report projects that the cost of next-generation geothermal projects, including AGS, will fall below that of other baseload power sources such as nuclear and natural gas with carbon capture and storage (CCS) by 2035. Other projections suggest that geothermal electricity could drop to around US$50/MWh by the 2030s, competitive with other renewables and nuclear. Finally, AGS leverage a skilled workforce and supply chain from the oil and gas sector. The necessary drilling rigs, subsurface imaging, and engineering expertise already exist, which could help scale up AGS faster than entirely new industries.

Why are we concerned?

Despite its promise, AGS face several challenges that temper its near-term prospects. To bridge the gap from pilot stage to commercialization, the industry needs more demonstration projects, case studies of success, and greater public trust. This is challenging because advanced geothermal projects today have high upfront capital costs, primarily due to deep drilling and, for EGS, hydraulic stimulation expenses, as well as high operational costs. Current AGS electricity is also far more expensive than conventional renewables, often hundreds of dollars per MWh. Until these costs decline, the industry may struggle to attract the investment financing needed to scale up. Moreover, the geological uncertainty in any given project is high because limited geophysical data in many regions makes it hard to pinpoint the best spots to drill. Developers must invest in exploration with no guarantee of finding an adequate resource, so early projects carry a significant risk of cost overruns.

Safety and environmental concerns also pose challenges. In some types of geologies, enhanced geothermal systems, which use hydraulic fracturing to create the heat exchange reservoirs and circulate fluid underground, can trigger small earthquakes. Some EGS have been halted after local earthquakes caused alarm and minor damage. Because they use water and circulate hot brines, AGS could pose risks for groundwater contamination or water consumption in arid regions, although geothermal system designs that use closed-loop systems or non-potable water can avoid these problems. Finally, geothermal projects often face regulatory and logistical hurdles and lengthy permitting processes. In many countries, regulatory regimes and incentives have focused on solar, wind, and even nuclear, while geothermal energy (and especially AGS) has received comparatively little support. This means AGS developers may struggle with financing and grid access due to policy gaps or obstacles. 

What is our assessment?

Based on our analysis, improving district heating for industry by integrating low-carbon heat sources has the potential to significantly reduce the use of fossil fuels and the emissions they generate. However, the lack of data, combined with the complexity of such projects and the growing interest in alternative decarbonization pathways, makes this a potential solution to “Keep Watching.”

What is it?

District heating systems consist of a network of underground pipes that distribute heat to a large number of buildings, including industrial buildings. In the industrial sector, district heating is used by light industries and for processes such as drying, paper making, food processing, as well as space heating and even heat-driven refrigeration (Bellevrat & West, 2018; Difs et al., 2009). Industry is well suited to district heating because it typically has steady and predictable heat demand throughout the year. Current district heating systems rely heavily on coal and natural gas for heat generation, often as part of combined heat and power generation (IEA, 2026). Low-carbon alternatives for district heating can include electric boilers, electric heat pumps, solar thermal, deep geothermal, and even waste heat from other industries (IEA, 2026; International Renewable Energy Agency [IRENA] et al., 2020). 

Does it work?

Shifting district heating for industry from conventional heat sources to low-carbon heat sources will significantly reduce emissions. Our analysis for district heating use by commercial and residential buildings shows that significant emissions can be avoided by shifting to electric boilers, heat pumps, and the use of waste heat (see Improve District Heating: Buildings). Similar outcomes are likely possible for industrial district heating use, and emissions reductions will increase as more renewables are integrated into the electricity systems used to power electric boilers and heat pumps. 

Why are we excited?

District heating for industry currently produces significant emissions. According to the IEA (2026), district heating and cooling for all applications accounted for roughly 5% of global energy consumption in 2024, and roughly 40% of the heat energy from district heating was delivered to industry IEA, 2022). China is a major adopter of district heating for industries, with the combustion of coal supplying much of that heat (IEA, 2026). The shift to renewable heat sources is likely to increase because both China and the EU have policies targeting the adoption of renewables in district heating (European Commission, 2022; IEA, 2026). Because district heating systems serve multiple buildings, a single project to replace fossil fuels with renewables can have a large impact. Such projects also have the benefit of reducing local air pollution. 

Why are we concerned?

Although simple on paper, replacing fossil fuel systems with lower-carbon alternatives in district heating systems can be an extended undertaking involving many stakeholders and years of planning (Lake et al., 2017; Werner, 2017). Some low-carbon options may not be suitable for industrial processes that require higher temperatures than those needed for space heating (Bellevrat et al., 2018). There is also a significant lack of publicly available data about how industry currently uses district heating and the opportunities and challenges involved in shifting to renewables. In the meantime, industrial heat pumps with higher temperature outputs are increasingly available and could become a low-carbon competitor to the use of a conventional district heating system (IEA, 2026).

What is our assessment?

Because incineration of waste to produce electricity and/or heat does not reduce emissions in most circumstances, and it can displace or disincentivize other, more effective waste treatment practices, Deploying Waste to Energy is “Not Recommended” as a climate solution.

What is it?

Waste to energy (WTE) uses high temperature incineration (above 800^oC) of waste, including municipal solid waste (MSW), medical or hazardous waste, and waste biomass from agriculture and forestry, to generate electricity and/or heat. This energy production technology can be used to displace fossil fuel energy sources. However, like fossil fuels, the incineration process produces GHGs during combustion, primarily CO₂ and nitrous oxides, as well as ash and other pollutants as byproducts. WTE also diverts waste from landfills and open dumps, avoiding high-impact methane emissions from decomposing organic materials and pollution and health risks from inorganic or toxic materials. Globally, there are more than 1,700 WTE plants. According to the International Energy Agency (IEA) World Energy Balances, WTE from industrial and municipal waste accounted for less than 0.5% of global energy production in 2022. Around 62% of WTE plants are in Asia, 33% are in Europe, and 4.5% are in North America. Other waste to energy technologies, such as pyrolysis and gasification, which use heat to convert organic materials into various forms of syngas, are evaluated in other Drawdown Explorer solutions and not included here. 

Does it work?

The effectiveness of WTE for reducing GHG emissions when substituting for fossil fuels for heat and energy, while also avoiding landfill emissions, is highly variable. Effectiveness varies with waste type and quality, combustion characteristics, air pollution controls, alternative disposal methods, and the type of electricity generation that it displaces. WTE incineration is less energy efficient than natural gas or coal for producing electricity (20–30% for WTE compared to 40–60%), and relatively more waste must be burned to produce comparable amounts of energy. WTE incineration is also less energy efficient than pyrolysis (40–75%), gasification (40–60%), and even methane digestion (30–40%). In regions that incinerate large proportions of plastic waste, such as South Korea and China, emissions are higher than for landfilling the waste. For some waste streams in some regions, other treatment strategies such as recycling, composting, pyrolysis, gasification, or the production of biochar, bio-oils, or bio-bricks yield greater emissions reductions.

Why are we excited? 

WTE can reduce waste volumes by up to 90%. In high-income regions without available land for sanitary landfills with landfill gas capture systems (see Improve Landfill Management), incineration is a viable alternative for post-recycling, hazardous, industrial, or medical waste. However, incineration of these waste streams requires strict standards, advanced air pollution control systems, and continuous monitoring to minimize harmful emissions of toxic pollutants. 

Why are we concerned?

In almost all circumstances, incinerating waste to produce reliable electricity or heat is not an effective method for reducing GHG emissions. WTE plants require a steady stream of waste feedstock to ensure ideal combustion conditions for electricity and heat production. This can incentivize waste production and disincentivize alternative waste treatments that reduce emissions more effectively. For example, in the European Union (EU), where incineration is widely used, some countries need to import waste to maintain energy production. This offsets some or all of the potential climate benefit due to emissions during transport and may divert attention from better waste management solutions, such as regulations on packaging, recycling, and composting. In other countries, high incineration rates of MSW (above 30%) are correlated with declines in recycling rates. For example, in 2018, Japan incinerated over 80% of MSW while only 4.9% was recycled. Recent policy initiatives there now focus on increasing recycling, which effectively and consistently reduces emissions, and decreasing incineration through source separation of waste. According to one study, chemically recycling plastic waste rather than incinerating it saves 0.82 kg CO₂‑eq /kg of feedstock. 

WTE is a substantial source of toxic air pollution. Poorly constructed, unregulated incinerators generate air pollution and large amounts of ash that will need further treatment. Advanced air pollution control systems are required to minimize emissions of GHGs and pollutants, including particulate matter, sulfur dioxide, nitrogen oxides, carbon monoxide, other acid gases, heavy metals, and persistent organic pollutants like dioxins. Even in high-income countries with strict air quality standards, polluting incinerators are disproportionately sited in under-resourced communities, which exacerbates environmental justice issues. In the United States, 79% of incinerators are located in low-income or minority communities. 

Finally, WTE is the most expensive waste management method in most regions, largely due to high capital costs. In 2018, all countries using industrial incinerators for incinerating more than 10% of MSW were high-income, except China. The addition of necessary emission control and monitoring systems further increases costs, making WTE more expensive than methane digesters or landfills with gas capture systems.

What is our assessment?

Using CCS on fossil-fueled power plants will reduce electricity production emissions, but it is more expensive, more energy-intensive, and more polluting than readily available, cheaper, and cleaner alternatives like wind, solar, and geothermal. Based on this, and the risk that large-scale deployment of CCS on fossil-fueled power plants could drive continued production and use of coal and gas, we conclude that using CCS on fossil fuel power plants is “Not Recommended” as a climate solution.

What is it?

Carbon capture and storage (CCS) is a technology that reduces GHG emissions from fossil fuel-powered electricity generation facilities by selectively capturing CO₂ from the power plant’s exhaust flue, preventing it from entering the atmosphere. The captured CO₂ is then concentrated, compressed, and permanently stored underground. There are other commercially available CCS technologies, such as pre-combustion capture and oxy-fuel combustion, but these are used almost exclusively for industrial processes like gas processing and cannot be readily retrofitted to existing power plants. CCS can also be applied to capture CO₂ from other industrial facilities that generate emissions from fuel combustion or production processes, like cement or ethanol production plants, or from biomass energy power plants. Instead of permanent storage, captured CO₂ can also be used as a chemical precursor for the manufacture of other products or for enhanced oil recovery, but, compared with geologic storage, these post-capture uses of CO₂ emit GHGs, thereby reducing or eliminating the emissions reduction efficacy of CCS. 

Does it work?

The technology and chemistry for the selective capture of CO₂ from the exhaust of a power plant are effective. There are numerous chemical, membrane, and cryogenic methods for capturing CO₂, but monoethanolamine (MEA) is the predominant commercially available chemical absorbent currently in use in power plants with CCS. CO₂ capture efficiency varies with the type of reactive absorbent material and plant operations. Most CCS installations target 90% CO₂ capture rates, although actual capture rates are usually lower. CCS infrastructure is large, and the process of capturing CO₂ from power plant exhaust is complex, expensive, and energy-intensive. CCS requires the flue gas to be pumped to different parts of the power plant, the CO₂ to be captured and then separated from the sorbent material, and the concentrated CO₂ to be compressed for transport and storage. Energy for all these processes comes from the power plant. Various studies estimate CCS consumes at least 15–25% of the plant’s total generation capacity, with most of the energy used to separate the CO₂ and regenerate the sorbent material. 

CCS has been used in pilot studies and commercial operations in a few dozen coal and natural gas power plants since the late 1990s. Despite the functional effectiveness of the technology, use of CCS to reduce power plant emissions has not been broadly adopted, and most CCS projects initiated in the past three decades have failed or been discontinued. Based on various assessments and projections, deployment of CCS on power plants has consistently lagged behind its expected contribution to emissions reduction. There are currently only four power plants with CCS in operation in the world, less than 0.05% of the global fossil-fueled power plant fleet. According to a 2021 study, only 10% of proposed CCS projects for power plants have actually been implemented. Based on another study, 78% of all power plant and industrial manufacturing CCS pilot and demonstration plants with a project size greater than 0.3 Mt CO₂ /yr have been cancelled or put on hold. 

Why are we excited?

Globally, emissions from coal- and gas-fired power plants are still increasing, primarily in China and India, where large numbers of new thermal power plants have been built in the last two decades. Given the typical 30- to 45-year operational lifespan for coal and gas power plants, retrofitting these newer plants with CCS could substantially reduce their operational emissions while also allowing plant owners and investors to recover their investments. Installation of CCS to reduce emissions can also be prioritized for power plants located near places with geologic storage and where alternative electricity generation options are limited. There is a large amount of research underway to develop and test alternative carbon capture technologies, most aimed at increasing carbon capture efficiencies and reducing energy demands and costs. Other research on the factors contributing to the failure of most CCS projects to date may lead to the development of regulations and policies that require or incentivize the use of CCS for power plants, which could increase the current low implementation and success rates for this emissions reduction technology. 

Why are we concerned? 

While CCS can reduce the operational CO₂ emissions from fossil-fueled power plants, large-scale deployment of this technology will likely drive continued production and use of coal and gas. Even before fossil fuels are burned, extraction, transport, and processing generate substantial GHG emissions, particularly for gas. Therefore, in addition to perpetuating the fossil fuel industry, even 90% efficient CCS reduces only a fraction of the life cycle emissions from coal and gas. 

Widespread deployment of CCS in the electricity sector could also delay or crowd out deployment of wind, solar, and geothermal energy, slowing the clean energy transition that is already underway. Beyond these risks, the three-decade-long failure of power plant CCS to make the transition from pilot-scale science and technology to large-scale commercial deployment reflects its systemic problems and limitations. Unlike wind and solar energy, which have seen costs decline rapidly with development and deployment, CCS on power plants shows little evidence of a learning curve. It remains very expensive and very energy-intensive. A large-scale CCS demonstration project can cost more than US$1 billion to build and, in addition to its operational costs, CCS consumes at least 15–25% of the energy that the plant could otherwise sell to customers. CCS-related energy requirements could mean that a power company would need to build an additional power plant to compensate for reduced electricity deliveries from every four of its power plants equipped with CCS. 

Due to these high project risks and costs, as well as the lack of regulations and policies to require or support CCS on power plants, public and private investments in the technology have been falling. Despite all this, recent research shows that the vast majority of lobbying spending for government support of CCS comes from fossil fuel interests, which have publicly stated that they view the technology as a strategy to extend society’s use of fossil fuels. Finally, in contrast to most other climate solutions that provide other benefits to natural systems or human well-being, CCS on power plants does nothing to address or alleviate the current harm from toxic air pollution produced by fossil-fueled power plants.

What is our assessment?

Based on our analysis, SMRs are a plausible and potentially impactful climate solution, but they are not yet ready for widespread deployment. The core technology is credible and carries significant potential for reducing GHG emissions. However, readiness, cost certainty, and deployment evidence are still lacking. For now, we will “Keep Watching” SMRs.

What is it?

Small modular nuclear reactors (SMRs) are advanced reactors that produce low-carbon electricity by harnessing the heat from nuclear fission, an established and well-understood physical process. The innovation of SMRs lies primarily in their design. Typically smaller than traditional reactors, with a capacity of less than 300 megawatts (MW), SMRs are factory-built for enhanced quality control. This design allows them to be delivered to installation sites more quickly and potentially at a lower cost compared to conventional reactors, which typically range in capacity from about 700 MW to over 1,600 MW. While SMRs are generally considered "utility-scale" in their capacity, their smaller size makes them a viable option for smaller-scale applications, such as large micro-grids. These reactors can be assembled in a modular fashion, allowing incremental capacity additions. Additionally, some SMR designs boast enhanced safety features, including passive cooling systems that can function without external power sources, reducing the risks associated with reactor overheating or meltdowns. Currently, several countries are planning the deployment of SMRs, particularly China and the United States. Given their modular nature, several African countries, such as Ghana, are also looking toward SMRs to address their energy access deficits. Based on current plans, the International Energy Agency expects several countries to have multiple SMRs installed and operational by around 2030.

Does it work?

The physics behind SMRs is sound, and their potential as low-carbon energy sources is also scientifically valid, as they do not emit GHG emissions during operation. Several pilot SMR projects have also been launched. SMRs have yet to move beyond the demonstration phase to widespread commercial adoption. No SMR is currently deployed at the scale necessary to reduce global emissions measurably. Furthermore, independent, peer-reviewed empirical data on long-term operational performance, scalability, and cost remain sparse. While several countries, including the United States, Hungary, China, and Ghana, have announced plans or are discussing deploying SMRs within the next decade, those plans are still in the preparatory stages.

Why are we excited?

SMRs have several features that make them appealing as a potential climate solution. If scaled appropriately, they could displace fossil-fuel-based power generation and reduce carbon emissions significantly. Projected deployment scenarios by the Nuclear Energy Agency suggest that by 2050, the global SMR market could reach 375 gigawatts of installed capacity, avoiding up to 15 Gt of cumulative CO₂ emissions. Their smaller size and modular nature reduce financial risk, making them potentially more accessible to developing countries or smaller utilities. They are also flexible in siting and can complement variable renewable energy sources like solar and wind by providing reliable baseload or backup power. Additionally, SMRs could help decarbonize hard-to-electrify sectors like process heat in industry or remote energy systems. These attributes have prompted excitement among proponents who see SMRs as a scalable, flexible, and resilient solution for emissions-free power. 

Why are we concerned?

Despite their promise, SMRs face several challenges that limit their readiness for large-scale deployment. Safety remains a concern – not necessarily because of design flaws, but because any nuclear reactor carries inherent risks. Waste disposal and the potential for proliferation of nuclear materials remain persistent issues. Regulatory hurdles are also significant, as existing frameworks are often geared toward conventional reactors and may slow the licensing of newer designs. The cost of SMRs is another outstanding question. Recent analyses by Wood Mackenzie suggest that SMRs could cost US$6,000 to US$8,000 per kilowatt of capacity, which is well above the costs of utility-scale solar (US$1,448) or onshore wind (US$2,098). Deployment timelines also pose a challenge. Given the urgency of climate action, technologies that cannot be deployed at scale within the next 10–15 years may offer limited near-term benefits. A recent study by the Institute for Energy Economics and Financial Analysis opines that SMRs are still too costly, too time-consuming to construct, and too risky to significantly impact the transition away from fossil fuels in the next decade. While peer-reviewed academic studies have been conducted, a comprehensive, independent evaluation of large-scale deployment remains absent.

What is our assessment?

Based on our analysis, nuclear fusion is a promising alternative form of electricity generation, but it is still at a theoretical stage and will not be ready for large-scale deployment within the next 10–15 years, when it could have the most impact on meeting global climate targets. We will “Keep Watching” this potential climate solution.

What is it?

Nuclear fusion is the process by which two individual elements are fused together into a single larger element using high pressure and temperature; this reaction releases large amounts of energy. This is the same reaction that happens in stars such as the sun. The energy from the fusion reaction can then be harnessed to produce electricity without emitting GHGs. Nuclear fusion power plants are best suited for centralized, large-scale generation (500 MW–1.2 GW of electricity output).

Does it work?

Nuclear fusion experiments have been carried out that prove the scientific principle is sound. However, only in recent years have experiments succeeded in producing more energy than was needed to initiate and sustain the fusion reaction. There have been no nuclear fusion power plants built to date, and it is unlikely that nuclear fusion–powered electricity generation will be ready for deployment before 2050.

Why are we excited?

Nuclear fusion energy offers several advantages as a solution to climate change, including high power density, the ability to deliver “firm” power (i.e., power that can be relied upon to meet demand when needed), and no GHG emissions. In addition, the most commonly used fuel for nuclear fusion – hydrogen – is readily accessible, there is no risk of a nuclear meltdown, and the process produces relatively little nuclear waste, meaning the risk of nuclear proliferation is almost nonexistent. Some research suggests that nuclear fusion could provide up to 15% of total electricity production either by replacing existing centralized power plants (e.g., oil and gas, coal, nuclear fission) that have reached end-of-life or to satisfy growing demand for electricity as access and electrification increase.

Why are we concerned?

Nuclear fusion is not considered remotely close to being ready to deploy as a climate solution. It faces many technical challenges, including uncertainties related to fusion reactor design and optimal fuel types. The costs for nuclear fusion–produced electricity are highly uncertain and are expected to grow compared to existing estimates. Current estimates for nuclear fusion energy costs exceed US$150/MWh, nearly double the 2020 price per MWh for other energy sources. There are also large uncertainties about the policy environment for nuclear fusion plants, which could hinder both development and deployment. Currently, projections suggest that nuclear fusion reactors could be introduced between 2050 and 2060. This means that even under optimistic conditions, nuclear fusion is unlikely to make a significant contribution to meeting 2050 emissions reduction targets. 

Electricity generation accounts for an estimated 23% of GHG emissions on a 100-year basis (Clarke et al., 2022), with fossil fuel–based sources supplying more than 60% of electricity generated in 2023 (International Energy Agency [IEA], 2024b). Since solar PV is a clean and renewable resource, agrivoltaics produces electricity without contributing to GHG emissions or air pollution during operation. Unlike conventional utility-scale solar PV, which often competes with agriculture for space, agrivoltaics combines solar PV electricity generation and agricultural production without requiring additional land use change or sacrificing arable land (Trommsdorff et al., 2025).

The primary climate benefit is the reduction of CO₂ emissions and smaller amounts of methane and nitrous oxide from displacing fossil fuel–based electricity from the grid. This solution quantifies only emissions avoided through electricity generation and does not include emissions from agricultural activities beneath or between the solar panels.

Agrivoltaic systems come in several configurations to coexist with different agricultural activities, including crop production, animal husbandry or grazing, ecosystem services, aquaculture, and pollinator habitat (Macknick et al., 2022). As shown in Figure 1, these systems range from standard ground-mounted arrangements – with crops growing between rows or livestock grazing underneath – to more specialized alternative designs such as elevated panels, vertical bifacial mounts, stilt-mounted trackers, and solar-integrated greenhouses. Overhead configurations elevate panels 2–6 meters above ground to allow standard farm operations while providing shade and weather protection for crops or livestock. Interspace (or interrow) configurations leave wide alleys between ground-mounted PV arrays for vegetation. Rooftop and structure-mounted configurations place panels on greenhouses, barns, or other farm infrastructure, using rigid or flexible panels (Campana et al., 2025; Macknick et al., 2022; Solar Power Europe, 2024a; Trommsdorff et al., 2021).

Each configuration involves different trade-offs between energy output, crop performance, land compatibility, and cost (Campana et al., 2025; Horowitz et al., 2020; Trommsdorff et al., 2025). Well-designed systems often achieve higher overall productivity with a land equivalent ratio exceeding 1 (Trommsdorff et al., 2025). Successful implementation typically requires partnerships among farmers, agricultural cooperatives, solar developers, and utilities, supported by government policies such as subsidies, tax credits, or zoning support (Trommsdorff et al., 2025). 

What is our assessment? 

Based on our analysis, micro wind turbines (MWTs) are a promising technology for reducing emissions, but given the limited potential for global adoption and variable financial viability, they do not meet our threshold for global climate solutions (<0.1 Gt CO₂‑eq/yr ). Despite the low climate impact and high costs, Deploy Micro Wind Turbines is an important solution for achieving energy equity. Based on our assessment, we will “Keep Watching” this potential solution.

What is it? 

MWTs are small-scale turbines that rely on natural wind to generate electricity, charge batteries, or power equipment. Specific definitions for MWTs vary from country to country. Our analysis assessed energy production and GHG emissions reduction potential for wind turbines rated to generate a maximum of 100 kW of electrical power. MWTs are actively used for a variety of applications, including telecommunications, lighting, and agriculture. The total installed capacity for MWTs globally as of 2023 is nearly 1.8 GW or 0.002% of utility-scale onshore wind capacity. MWTs are most commonly used in rural settings.

Does it work? 

When connected to a regional or national electricity grid, MWTs can reduce baseline electricity grid emissions by reducing reliance on fossil fuel energy sources. Off-grid MWTs, which accounted for more than 90% of commercial sales in 2019, help electrify industrial and agricultural processes that otherwise may have been powered by fossil fuels, such as diesel or natural gas. Energy production from MWTs is highly dependent on the availability of consistent wind speeds, with the majority of turbines requiring an average wind speed of around 5 m/s to generate electricity. As long as sufficient wind resources are available, MWTs are effective at producing electricity to meet local energy demand and reduce reliance on fossil fuels.

Why are we excited? 

MWTs reduce reliance on fossil fuels for electricity generation, whether they are connected to an electric grid or isolated for local energy use. For grid-connected systems, more available renewable energy sources reduce the need for fossil fuel–based energy generation to meet demand. MWTs isolated from the electricity grid still reduce the local carbon footprint of a household, farm, or commercial building. Globally, the average household consumes approximately 17,000 kWh of electricity annually. Depending on the size of the turbine, local wind energy can produce 1,000–20,000 kWh/yr. Fluctuations in wind speed throughout the day and year can lead to unreliable power output, but this risk can be reduced by integrating batteries or hybrid electricity generation systems, such as combining wind and solar photovoltaics (PV). In addition to emissions reduction, MWTs are crucial tools for expanding electricity access worldwide. Since MWTs can operate independently of an electric grid, they can electrify rural areas where transmission lines are nonexistent or challenging to install. For example, many populations in Africa live in remote areas that could be well-served by installing MWTs to power telecommunications and other local electrification needs. Increasing interest in smart energy systems and Internet of Things technologies presents promising future applications for MWTs.

Why are we concerned? 

While MWTs show potential for expanding electrification, they have a number of limitations compared to other small-scale renewable energy technologies, like solar photovoltaics. First, real-world performance due to wind speed variability and turbulence at installation sites can be unpredictable and is often substantially lower than manufacturers’ power ratings. Second, life-cycle emissions from manufacturing and installation can be more than five times higher for small-scale wind than for large, multi-MW turbines. Energy payback times – the time period for the MWT to generate enough clean energy to offset the energy used during manufacturing and installation – can be long, sometimes exceeding the 20– to 25-year lifetime of the turbine. Third, MWTs are expensive, with up-front costs ranging from approximately US$3,000/kW to more than US$10,000/kW. Even after including financial incentives to partially offset high upfront costs, the levelized cost of electricity (LCOE) for residential MWTs in the United States was estimated at US$0.28/kWh. Not only was this higher than average U.S. residential electricity rates (US$0.1–0.24/kWh), but it was also more than double the LCOE for residential solar PV (US$0.12/kWh). Finally, noise pollution and vibration are environmental concerns for the wide-scale adoption of MWTs in urban areas. In addition, MWT performance can be poor in urban and suburban areas because buildings and other obstacles disrupt airflow. There is a general consensus in the scientific community and commercial market that MWTs are worthwhile electricity sources for many agricultural and industrial applications where cost is less prohibitive, but they remain a niche technology due to uncertain global economic viability and lack of reliable power generation in suburban and urban areas.