What is our assessment?

Enhanced geothermal systems (EGS) are emerging as one of the most promising technologies for reliable, utility-scale, zero-carbon energy that can complement wind and solar and strengthen grid resilience. The technology, which is built on an existing base of technical and industrial expertise and capacity, is advancing rapidly through major R&D efforts and early commercial pilots. 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?

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

Does it work?

Electricity production by an enhanced 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 was 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 EGS that use the 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 EGS projects have successfully produced electricity, but no EGS plant has yet achieved full commercial operation at scale. 

Why are we excited?

Enhanced geothermal energy systems are a potentially transformative climate solution for several reasons. First, they could massively expand clean energy availability. EGS 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, including EGS, could supply around 15% of the world’s electricity by 2050. Second, unlike solar and wind energy, enhanced 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. EGS 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, EGS 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 EGS. The application of horizontal 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 EGS. 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 EGS, 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, EGS 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 EGS faster than entirely new industries. 

Why are we concerned?

Despite its promise, EGS 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 enhanced geothermal projects today have high upfront capital costs, primarily due to deep drilling and reservoir stimulation expenses, as well as high operational costs. Current EGS 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. Currently, many EGS use hydraulic fracturing to create the heat exchange reservoirs and circulate fluid underground. In some types of geologies, this 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, EGS could pose risks for groundwater contamination or water consumption in arid regions, although EGS 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 EGS) has received comparatively little support. This means EGS developers may struggle with financing and grid access due to policy gaps or obstacles.  

What is our assessment?

Based on our analysis, Improve Steel Production using H₂-DRI-EAF powered by clean electricity has the potential to significantly reduce emissions. However, while the individual technologies for H₂-DRI-EAF are mature and their combined use has been piloted, the process has not yet been adopted in a meaningful way. We will “Keep Watching” this solution, but it is not ready for widespread adoption.

What is it?

Currently, making steel from iron ore relies heavily on coal and other fossil fuels to provide heat and reducing agents (chemicals that remove oxygen from iron ore). Improve Steel Production refers to using electric heat and hydrogen produced by electrolysis to reduce the iron ore (H₂-DRI) and electric arc furnaces (EAF) to melt the resulting iron and alloy it with carbon to make steel. The solution also requires the electricity used in these processes to include significant renewable energy or other low-carbon generation. The output is varying grades of steel with different degrees of hardness and brittleness determined by slight variations in carbon content. This solution does not include processes that rely on bioenergy or CCS, since the emissions from burning bioenergy contribute to climate change and CCS is not an effective climate solution.  

Does it work?

Replacing fossil fuels in steelmaking with H₂-DRI-EAF that uses electrolytic hydrogen and where all electricity comes from relatively clean sources results in significantly reduced emissions. Steel made today using fossil fuels for heat and as a reducing agent results in an estimated 1.8 t CO₂‑eq /t of steel. By contrast, steel made using H₂-DRI-EAF and low-carbon electricity would generate an estimated 0.12 t CO₂‑eq /t of steel and is a more energy-efficient process. EAF furnaces are already very common in steelmaking and for recycling existing steel, but are rarely combined with H₂-DRI. Although H₂-DRI was first used on an industrial scale in 2001, that plant was shut down for economic and political reasons, and economics remain a barrier. Finally, technologies to make industrial hydrogen from electricity are mature, but most hydrogen produced today is made from fossil fuels and is carbon-intensive. Active research is exploring other technologies that could become important for improving steel production in the future, most notably aqueous or molten oxide electrolysis, both of which use electricity to directly remove oxygen from iron ore, and can be combined with EAF to make steel.  

Why are we excited?

Steelmaking is classified as a hard-to-abate industry, and H₂-DRI-EAF powered by clean electricity is considered one of the best strategies for cutting emissions in this sector. The Net Zero Industry project forecasts that under an emissions-neutral steel scenario by 2050, roughly 40% of global steel production could depend on H₂-DRI-EAF, with the remainder consisting of recycled steel (47%), steelmaking with CCS (11%), or technologies not yet defined (2%). The impact is potentially significant, given that steelmaking accounted for an estimated 3.7 Gt of CO₂‑eq in 2019. Improved steelmaking has the additional benefit of reducing air and land pollution, as burning coal releases fine particulate matter, heavy metals, and other pollutants. In China, steel production is the largest industrial source of air pollution. As demand for steel is expected to increase up to 30% by 2050 due to demand from India and other low- and middle-income countries, it is critical that new and existing production shift to cleaner, lower-emission technologies, and that policies supporting this shift be implemented.  

Why are we concerned?

While proposed low-emission steel projects have attracted significant attention from the press, many have since been canceled or put on hold. As of 2025, we could find references to only a few pilot facilities producing improved steel as we have defined it here. The entire H₂-DRI-EAF process is considered to be at the large-scale prototype demonstration stage. However, contributing technologies such as electrolytic hydrogen production and EAF are more mature, and H₂-DRI was first used on an industrial scale in 2001. The higher cost of making low-emission steel is a significant barrier to industrial adoption and consumer demand. Electricity accounts for nearly half the cost of producing low-emission steel from iron ore. To increase adoption, improved steel facilities need to be located in areas that can readily supply both iron ore and abundant low-carbon, low-cost electricity. In areas such as China, where the electricity grid still relies heavily on fossil fuels, transitioning to H₂-DRI-EAF risks increasing emissions unless dedicated renewables are integrated into the project. To move this solution forward, new policies are needed to create an international market for low-emission steel. Meanwhile, existing steelmaking facilities typically have lifetimes of 25–40 years, which increases the likelihood of stranded assets or continued reliance on fossil fuels by 2050. Under its Sustainable Development Scenario, the International Energy Agency (IEA) projects that, by 2050, only 12% of cumulative direct emissions reductions in steelmaking will be due to electrification and the use of hydrogen (the IEA considered emissions from electricity to be indirect). Reducing demand for steel, incremental efficiency gains, and CCS are expected to make up the bulk of cumulative direct emissions reductions, according to the IEA projections.

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 chillers for refrigeration. 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. Low-carbon alternatives for district heating can include electric heat pumps, solar thermal, deep geothermal, and even waste heat from other industries. 

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 International Energy Agency (IEA), district heating for all applications accounted for 4% of global emissions in 2022, and roughly 40% of the heat energy from district heating was delivered to industry. China is a major adopter of district heating for industries, with the combustion of coal supplying much of that heat. 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. 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. Some low-carbon options may not be suitable for industrial processes that require higher temperatures than those needed for space heating. 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 (100–200°C) are increasingly available and could become a low-carbon competitor to the use of a conventional district heating system.

What is our assessment?

Based on our analysis, we find that fishing vessel efficiency improvements are ready to deploy and feasible, but probably have limited climate impact because the wild capture fisheries sector contributes a relatively small share of global GHG emissions. These improvements will likely provide long-term cost savings and added benefits for ecosystems and air quality. We conclude this climate solution is “Worthwhile.”

What is it?

Improving fishing vessel efficiency reduces CO₂ emissions by using gear, vessel, or operational changes that lower fuel use in wild capture fisheries. Vessel upgrades include propulsion-related changes, such as installation of more efficient engines, and non-propulsion-related alterations, such as modified bows and hulls that reduce drag. Changing to low-fuel-use gear to catch fish, when and where possible, can also reduce CO₂ emissions. Operational changes, such as speed reductions or route optimization, can likewise lead to more efficient fuel use.

Does it work?

Vessel efficiency improvements are expected to deliver substantial fuel savings. An estimated 60–90% of emissions in wild capture fisheries, which emit roughly 0.18 Gt CO₂‑eq/yr in total, likely result from fuel consumption. Speed reductions alone can reduce fuel use by up to 30%. Vessel modifications could provide fuel savings of up to 20% in small fishing vessels, which comprise roughly 86% of all motorized fishing vessels globally. Upgrading engines and other propulsion-related equipment can reduce fuel use by up to 30%. Gear switching, when viable, can also be highly effective at improving fuel use efficiency, particularly if the target species are typically caught using methods such as trawling, which has a high carbon footprint. 

Why are we excited?

The average emissions per metric ton of landed fish in wild capture fisheries have grown by over 20% since 1990, highlighting the need for efficiency improvements. Many of these improvements can be implemented without sacrificing fishing effort or opportunities, and some operational changes, such as reducing vessel speed, can be done without any new equipment. All changes reduce fuel use, saving fishers money over time and likely resulting in fewer emissions of harmful air pollutants, such as sulfur oxides and black carbon. Some upgrades could deliver additional benefits to air quality and ocean ecosystems. Cleaner engines can further reduce air pollution through more complete combustion of fuel, and gear changes could benefit seafloor ecosystems, which can be damaged from bottom fishing practices, such as trawling and dredging. Additionally, some fishing gear has high bycatch rates, and switching to gear that allows for more exclusive capture of target species can reduce waste.

Why are we concerned?

Even with widespread adoption, efficiency improvements that reduce fuel use are unlikely to have a major climate impact. Efficiency improvements could also inadvertently encourage increases in fishing effort, which would increase fuel use and offset emissions cuts. Initial costs to upgrade can be highly variable, but might be high in some cases and therefore not feasible for some fishers. Gear switching can result in lower fish catches, as some methods might not be as efficient. Some operational changes, such as reducing speeds, could lead to fishers arriving at fishing grounds late.

What is our assessment?

While Improve Aquaculture is unlikely to have a major climate impact, our assessment concludes that it is “Worthwhile” due to its ability to reduce pressure on wild fish stocks and terrestrial biomass, and because efficiency improvements made now are likely to scale into greater climate impact as the sector continues to expand.

What is it?

GHG emissions from aquaculture can be reduced by increasing the feed conversion efficiency of the cultured animals and decarbonizing on-farm energy use. Aquaculture – farming aquatic animals or plants for food or other purposes – is rapidly growing and now accounts for over half of the global production of aquatic animals, exceeding wild capture fisheries. Over 7% of human-consumed protein is aquaculture-produced. As this sector has grown, it has become increasingly reliant on external feed sources, with the share of non-fed aquaculture (e.g., bivalves that feed from the water column) dropping from nearly 40% in 2000 to 27% in 2022. Improving feed conversion ratios (FCR) – the amount of feed it takes to produce a given amount of biomass – can lower feed demand and reduce CO₂ and other GHG emissions tied to feed production and transport. FCRs can be improved by feed formulations that increase digestibility, genetic or breeding modifications to improve digestive efficiency in the cultured animal, species-specific feed formulations, and optimizing ration size and feeding frequency. At the same time, decarbonizing on-farm energy use can help reduce CO₂ emissions from common equipment, such as aerators and water pumps.

Does it work?

Interventions to improve feed and energy efficiency can reduce CO₂ emissions from aquaculture operations, although the potential achievable climate impact of these actions is currently unlikely to be globally meaningful (>0.1 Gt CO₂‑eq/yr ). Total annual emissions from aquaculture were estimated to be 0.26 Gt CO₂‑eq/yr in 2017, with nearly 60% of that attributed to feed production. Improving FCR is both plausible and effective, since it directly reduces the amount of food needed to cultivate fish and other species, thereby lowering emissions tied to feed production and transport. Between 1995 and 2007, improvements in FCR have ranged between 5 to 15% for a variety of species, including shrimp, salmon, carp, and tilapia.

Decarbonizing on-farm energy use can reduce equipment-related emissions, particularly in intensive systems that use energy for automated feeding systems, water temperature control, and circulation and aeration systems. In general, the potential impact of decarbonizing varies widely because on-farm energy use differs significantly across species and production systems. For instance, shrimp and prawn farming use nearly 20,000 MJ/t of live weight (LW), with over 75% from electricity, while bivalve production uses around 3,000 MJ/t of LW supplied largely by diesel.

Why are we excited?

Improving feed efficiency in aquaculture reduces demand for captured wild fish used in feed, reducing pressure on overfished stocks. It also lowers reliance on terrestrial biomass, such as soy, wheat, and rice, which come with additional land-use and emission costs. More efficient feeding can help reduce nutrient pollution, which can be responsible for high methane and nitrous oxide fluxes in some inland aquaculture systems. At the same time, decarbonizing on-farm energy use might ultimately lead to lower long-term operating costs and improved energy reliability.

Why are we concerned?

There are relatively few drawbacks associated with improving aquaculture. In the case of decarbonizing on-farm energy use, upfront costs could be high. For instance, installing solar panels or upgrading pumps can be financially challenging for small-scale operations. Energy use on farms can also vary throughout the day and night, which might not always align with renewable energy sources, like solar, without storage. 

What is our assessment?

Based on our analysis, blue hydrogen is feasible and ready to deploy, but there is little real-world evidence for its effectiveness or ability to scale. The expansion of this technology to replace current gray hydrogen production or to support the transition to a global hydrogen economy will perpetuate and possibly expand the use of fossil fuels. Because of this risk, we conclude that producing blue hydrogen is “Not Recommended.”

What is it?

Blue hydrogen production is an industrial process that produces hydrogen (H₂) from fossil fuels – either natural gas or coal – combined with carbon capture and storage (CCS) technology to reduce CO₂ emissions produced during the process. Today, most hydrogen is gray hydrogen made from natural gas without any CCS. The addition of CCS prevents the release of some of the CO₂ generated during the hydrogen production process; capturing, concentrating, and then storing it permanently underground. 

Does it work?

The technologies for making hydrogen from natural gas, predominantly steam methane reformation (SMR), are well established and have been used to produce hydrogen for close to a century. CCS technology is also available and currently deployed in multiple industrial and power generation applications. The SMR hydrogen production process generates GHG emissions from two sources: methane leaks from the gas used as feedstock and fuel used to power the production process, and GHG emissions from both the SMR process and combustion of gas (or other fuels) for energy, including CO₂, methane, nitrous oxide, and black carbon. CCS can be applied to capture CO₂ produced during the SMR process, for post-combustion capture of CO₂ from the plant’s energy use, or for both. Incorporating CCS to capture emissions from the hydrogen production process adds costs and increases energy use, but it could theoretically reduce CO₂ emissions by more than 90%. However, current adoption of blue hydrogen is very low – less than 1% of global hydrogen production – and there is little real-world evidence to support its effectiveness and scalability. The few commercial facilities currently in operation capture only about 60% or less of the emitted CO₂. Because CCS is energy-intensive, it requires more fuel to power the blue hydrogen production plant. This can also increase fugitive methane leaks due to increased gas-powered energy consumption. If implemented adequately, carbon storage can be permanent. The captured CO₂ can also be used as a chemical precursor for the manufacture of other products or for enhanced oil recovery; however, these post-capture uses of CO₂ emit GHGs, thereby reducing or eliminating the emissions reduction efficacy of CCS. Currently, only ~8% of CO₂ captured from blue hydrogen production is injected into dedicated geological storage, with the rest used in industry, enhanced oil recovery, and other applications. 

Why are we excited?

Hydrogen can be combusted as a zero-emissions fuel, used to store energy to produce electricity, or deployed as a feedstock in industrial, transportation, and energy systems. The production of any hydrogen type – blue, gray, or green hydrogen – could facilitate the expansion of hydrogen infrastructure and the development of the global hydrogen economy, which is an important step in scaling hydrogen. Blue hydrogen is more technologically ready and cheaper than green hydrogen, which is made from water using electrolysis powered by renewable energy. Blue hydrogen is more expensive to produce than gray hydrogen, but the cost per metric ton of CO₂ removed could be relatively low. Estimates range from US$60–110/t CO₂, although these costs are uncertain and, with lower CCS effectiveness, they could increase to ~US$260/t CO₂. If implemented with low fugitive methane emissions and high CCS efficiencies, blue hydrogen could substantially reduce emissions compared to current gray hydrogen production. The climate impact of scaling blue hydrogen could be high. Estimates and targets for blue hydrogen production by 2050 range from ~30–85 Mt hydrogen. At that scale, even modest emissions savings relative to gray hydrogen would have a climate impact above 0.09 Gt CO₂‑eq/yr by 2050. However, achieving this depends on the quality of the infrastructure and rate of technology scaling, both of which are unproven. 

Why are we concerned?

Currently, 6% of the world’s natural gas and 2% of its coal are used to make hydrogen. As hydrogen production ramps up, blue hydrogen – even though it reduces production emissions compared to gray hydrogen – would perpetuate and could even increase the global market for fossil fuels. If the future implementation of green hydrogen is set back, blue hydrogen could create a long-term dependence on fossil fuels. Furthermore, any hydrogen produced from natural gas leads to methane leaks, regardless of whether CO₂ is captured. Methane is a potent short-lived GHG, meaning its impact on climate warming is stronger in the near-term. This is why reducing methane emissions is an urgent emergency brake climate action. Building and expanding a new industry that relies on natural gas as both a feedstock and fuel, and which inevitably leaks methane, is counterproductive to solving the climate crisis. 

If and when there is a transition to a global hydrogen economy, blue hydrogen is a less effective climate solution than green hydrogen. Although this technology could be a transitional solution between gray and green hydrogen, blue hydrogen risks diverting resources away from green hydrogen development or ready-to-deploy renewable energy technologies, such as onshore wind or distributed solar PV. Expert opinions are mixed regarding the realistic level of avoided emissions that blue hydrogen may reach. Additionally, there is uncertainty around whether CCS can meet its technical potential at a reasonable cost.