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Firm Zero-Emission Power

Firm Zero-Emission Power

The challenge for deep decarbonization of the grid

A special report from FP Analytics, the independent research division of Foreign Policy Magazine

This Insider series explores the status of advanced technologies for deep decarbonization and remaining barriers to scale. The reports pinpoint areas for policy action and investment that could facilitate tech development and deployment and materially reduce emissions in some of the hardest-to-abate sectors. Read Part I here.

Wind and solar power resources have made incredible progress over the past decade, as supportive policies have led to a massive scaling-up of these technologies and precipitous cost declines that have made them the overwhelming choices for investments in power generation. In 2019, renewables accounted for over 80 percent of new capacity installed worldwide, and over 90 percent of it came from wind and solar. However, while generation capacity from these resources has grown considerably, it still accounts for a small share of actual generation, in part because they only generate power when the wind is blowing and the sun is shining. According to the International Energy Agency (IEA), wind and solar combined currently account for less than 10 percent of the global electricity mix.

Still, the share of electricity supply coming from these variable resources is growing rapidly, and they are proving adept at integrating them while maintaining reliability, even in areas where their share of the electricity mix is relatively high. A recent survey of over 40 electricity sector modeling studies found widespread agreement that the grid could be cost-effectively decarbonized by 50 to 70 percent through a combination of existing wind, solar, and battery technologies, along with flexible demand technologies capable of shifting consumption to hours of the day to match variable supply.

However, these studies also found that meeting more ambitious goals for a zero-emission grid may become much more technically challenging, as well as prohibitively costly, if grid operators rely exclusively on this set of technologies. Lithium-ion batteries and flexible demand can smooth out the daily variability of wind and solar, but they are not capable of storing electricity efficiently for days, weeks, or months at a time during extended or seasonal lulls, for example, during heat waves, when winds die down for multiple days, or winter months, when the sun shines for fewer hours. Models for wind and solar decarbonization scenarios rely heavily on massive overbuilding of wind and solar capacity to compensate for this seasonal variability as well as continent-scale transmission grid build-outs to connect wind and solar across time zones and regional weather patterns.

While it is possible that this challenge could be solved by the emergence of long-duration storage technologies, such as new battery chemistries or other physical or chemical storage approaches, these approaches are largely unproven and likely to be extremely expensive or outright impossible to deploy at the required scale. These looming challenges will become more serious as we increasingly rely on the grid to decarbonize transportation as well as for the cooling and heating needs of buildings, as “electrifying everything” will increase total consumption and the seasonality of demand.

Maintaining significant generating resources with operating characteristics similar to today’s power plants—often referred to as “firm” or “dispatchable” resources, because they can be ramped up and down at any time—would dramatically reduce the likely costs of deep decarbonization of the grid while also reducing technology risk by harnessing a more diversified portfolio of solutions. However, continued reliance on unabated fossil fuels is clearly incompatible with a zero-emission future, and today’s firm zero-emission resources all face formidable obstacles to increasing their share of the grid; hydropower and geothermal resources are proven low-cost solutions but geographically limited in their viability, and large-scale nuclear has gone from “too cheap to meter” to “too expensive to build” in competitive markets (to say nothing of political challenges in some countries).

The most likely firm zero-emission electricity resources of the future combine established dispatchable generation technologies with radical new approaches to overcome these limitations. Carbon capture, utilization, and storage can (almost) eliminate carbon emissions from fossil fuel power plants; advanced nuclear approaches promise to reduce capital costs, construction timelines, and safety concerns; and unconventional geothermal techniques could allow the heat emanating from the earth’s core to be tapped anywhere in the world instead of just in tectonically active regions.

Unlike wind and solar, these technologies are largely pre-commercial and will require significant public and private investments in R&D, demonstration, and deployment. However, because they all leverage proven technologies, they each have potential to be commercially viable in the next decade, and thus the ability to play a crucial role in achieving Paris Agreement-aligned targets for economy-wide decarbonization by mid-century.

CCUS: An Essential Tool for Decarbonizing Industry… and Fossil Fuel Power?

Carbon capture, utilization, or storage (CCUS), a broad category that combines carbon capture and storage (CCS) as well as carbon capture and utilization (CCU), is the most established and widely deployed of these potential candidates for firm zero-emission electricity. CCUS starts with the separation and capture of CO2 from the flue gas streams of a fossil-fueled power plant or other industrial facility, using any of a variety of chemical and physical processes. Then, these captured emissions are compressed and transported, typically via pipeline, to reach either customers for utilization (for example, a beverage-carbonation facility) or for injection at pressure into suitable long-term storage sites—primarily saline geological formations or depleted oil and gas wells. In essence, this permanent, geological storage returns the carbon produced by the combustion of fossil fuels to where it came from.

The appeal of CCS is clear. From a technical perspective, it allows utilities to continue building and relying on a familiar technology to anchor the grid, allowing them to bypass the operational challenges and other feasibility risks of decarbonizing with wind and solar alone. From an economic perspective, CCS equipment can be retrofitted on existing facilities, offering the promise of rescuing trillions of dollars of assets currently at risk of being stranded, including fossil-fueled power plants as well as oil, gas, and coal reserves. It also translates into a potential political advantage for CCS, as it creates opportunities for oil and gas majors as well as voters in fossil fuel-producing regions to participate in the zero-carbon transition instead of fighting a losing battle against increasingly ambitious emission-reduction goals.

However, CCS has its critics as well. From an environmental perspective, CCS is not currently a true solution for zero-emission power, as current approaches typically capture 85 to 95 percent of CO2 from power plants. And because CCS-equipped plants typically require 15 to 25 percent more fuel use to produce a given amount of electricity due to the additional energy consumption of the CCS process itself, they can also result in increased emissions of harmful local pollutants like NOx and particulate matter in the absence of additional controls, further undermining their environmental credentials. Finally, the aforementioned political advantages that CCS offers by enabling fossil fuel producers to participate in (and profit from) climate action is anathema to many advocates in light of the historical responsibility of these companies in obstructing climate policy in the past.

Thus, while CCS has the potential to be a critically important and broadly applicable climate solution embraced by both sides of the political spectrum, it is also at risk of becoming an “orphan” solution, abandoned by climate advocates who oppose all use of fossil fuels, as well as climate deniers who oppose any type of carbon reduction policy. Indeed, a flood of misinformation in recent years has worsened these challenges in public perception, from those seeking to obscure the reality of climate change on one side to those raising unfounded fears about the risks of this technology, for example, from catastrophic leaks from storage facilities, on the other side. Getting a clearer view of the promise as well as the limits of CCS requires first looking at the state of the technology and its track record to date.

CCUS Deployments to Date

Carbon capture technology was first deployed in the 1930s for the removal of CO2 from saleable natural gas deposits, although at the time this CO2 was not stored but instead used for applications ranging from industrial solvents to beverage carbonation. The storage of CO2 deep beneath the earth’s surface dates back to the 1970s, when CO2 captured from natural gas processing plants began to be reinjected in oil fields in Texas to boost output in a process called enhanced oil recovery (EOR). Only since 1996, when the Sleipner project began storing CO2 in saline formations in the North Sea, has CCS been used as a tool for climate mitigation on a commercial scale.

Today, the IEA counts 22 operating large-scale CCUS facilities globally with a combined capacity of capturing more than 40 metric tons (Mt) of CO2 every year, and 30 more projects in various stages of planning. While this existing base of projects has demonstrated the viability of CCUS and has proven that geologic storage is effective and safe (there have been no significant leaks or other incidents after decades of operation in some cases), this barely scratches the surface of what is required; the IEA’s Sustainable Development Scenario projects a need for 5.6 gigatonnes of storage per year by 2050. The majority of existing facilities are still deployed at natural gas processing plants, but the diversity of applications is steadily increasing to include capturing CO2 from power generation as well as from the production of fertilizer, ethanol, hydrogen, synfuels, and steel.

World CO2 Capture Capacity at Large-Scale Facilities by Source, 1980–2020

In megatonnes

Going forward, CCUS technology is very likely to find its most common and important applications in these industrial uses. As discussed in the first article, carbon capture is essential to the production of low-emission “blue” hydrogen from natural gas, which in turn is likely to be a key input for the decarbonization of industries, including steel and cement, as well as shipping and aviation. Beyond the need to produce hydrogen as a zero-emission fuel for industrial heat requirements, carbon capture is also needed to offset CO2 emissions inherent to processes such as cement calcination. Overall, the IEA’s recent, Paris Agreement-aligned Sustainable Development Scenario relies on CCUS to deliver as much as two-thirds of CO2 reductions from heavy industry and produce half of all aviation fuels through zero-carbon synfuels.

Beyond being essential for decarbonizing these “hard-to-abate” sectors that lack alternative pathways, the deployment of CCUS for most industrial uses also has a cost advantage over CCUS in power generation. As dictated by the laws of thermodynamics, the lower the concentration of CO2 in a flue gas stream and the lower its pressure, the more challenging and costly it is to separate out for capture and storage. Most industrial applications yield more concentrated and higher-pressure exhaust streams than power generation, with corresponding cost benefits. According to the Carbon Capture Institute, carbon capture can be accomplished at a cost of $20 per ton or less for large-scale natural gas processing, fertilizer production, or ethanol production, while costs for capture at a natural gas power plant are typically $100 per ton or more. Costs of capture from the higher-CO2 streams of coal plants, as well as steel and cement production facilities, lie in between the two.

According to IEA estimates, this translates into median levelized costs of $91 per megawatt-hour (MWh) for combined cycle natural gas with CCUS and $112 per MWh for coal with CCUS—roughly twice the levelized costs of wind and solar today. Of course, this is likely to become steadily more competitive as the cost of integrating more wind and solar rises with very high levels of penetration on the grid, as expected in the modeling studies discussed above. And because it is the most established firm zero (or near-zero) emission technology, it has the virtues of having relatively certain costs, compared to advanced nuclear or unconventional geothermal plants, whose future costs and technology development trajectories are less assured.

Overall, the IEA’s recent, Paris Agreement-aligned Sustainable Development Scenario relies on CCUS to deliver as much as two-thirds of CO2 reductions from heavy industry and produce half of all aviation fuels through zero-carbon synfuels. Moreover, CCUS paired with biomass-fired power plants—referred to as “BECCS,” for bioenergy with carbon capture and storage—offers the tantalizing prospect of yielding negative emissions, since biomass feedstocks sequester carbon as they grow, and the CCUS equipment captures the CO2 emissions from their subsequent combustion. While BECCS does not “capture” the imagination as much as direct air capture technologies do, has yet to be deployed at scale, and comes with well-founded concerns about the scalability and land-use emissions impacts of biomass fuel supplies, it is the only negative emissions solution based on existing commercial technologies. As such, some amount of BECCS is included in the majority of lowest-cost modeled pathways for meeting Paris Agreement goals, including the IEA Sustainable Development Scenario.

CCUS is a relatively mature technology, but there are still significant opportunities to reduce costs. Indeed, the cost of carbon capture from a coal-fired power plant has been reduced by roughly 50 percent over the past 15 years, according to the Carbon Capture Institute, largely through learning by doing, economies of scale, and a growing ecosystem of vendors as well as commercial partners for utilization projects like EOR. Further reductions in the cost of carbon capture—which accounts for the majority of total CCUS system costs—can be achieved through deployment at larger-scale facilities and the modular and standardized design of capture equipment, which allows equipment to be mass produced, and construction timelines to be accelerated (thus reducing capital costs and time to revenues).

While carbon capture is the chief cost driver of CCUS, its economics are also affected by costs for carbon transportation and storage. In transportation, pipeline economies of scale are driven by utilization levels, which can be increased by developing CCUS hubs around a variety of sources such as a natural gas processing facility located near a gas-fired power plant and a steel mill. Storage costs depend largely on the nature of the injection site in question; sites with well-characterized geology and access to existing infrastructure—chiefly oil and gas wells—are less expensive than previously unexplored greenfield sites. Onshore sites also generally offer much less expensive storage than offshore sites do, although they may face obstacles from existing or nearby land uses and/or public opposition to fossil fuel-related infrastructure.

Next-generation capture technologies offer the promise of further cost reductions and better emissions performance. A broad suite of pathways are being pursued, including improvements to core components such as solvents, sorbents, and membranes; advances in pre-combustion approaches that first remove CO2 from feedstocks in a syngas conversion process offering higher concentrations of CO2 than post-combustion capture; oxy-combustion plants that burn fossil fuels in nearly pure oxygen rather than air, yielding a concentrated stream of CO2 for highly efficient capture as well as the elimination of NOx emissions; and a variety of other techniques. While some of these technologies may be applied as retrofits, more advanced approaches such as oxy-fuel combustion require fundamentally different plant designs and must be developed on a greenfield basis. The U.S. Department of Energy’s Office of Fossil Energy has set R&D targets for demonstrating second-generation technologies capable of reducing CCUS electricity costs by 20 percent by 2025, with a goal of commercial deployments by 2030, and for “transformational” technologies capable of delivering a 30 percent reduction in cost to be available for demonstration in 2030 and deployment by 2035.

Carbon utilization could become a $1 trillion market by 2030 by some estimates Finally, the economics of CCUS can be improved in some cases, potentially significantly, in applications where captured CO2 can be sold to end-users. Indeed, the majority of the CCUS projects in the U.S. to date have been developed, thanks to revenues from sales of CO2 for EOR. While EOR is clearly not a desirable end-use market from a climate-change perspective, there are a growing range of other uses for CO2 being explored, including in concrete that uses CO2 instead of water in the curing process (which has the added bonus of strengthening the material), synfuels produced with clean hydrogen for aviation, various chemicals such as methanol and polymers, algae and algae-derived bioproducts, and carbon fibers.

Carbon utilization could become a $1 trillion market by 2030 by some estimates, providing a critical source of market pull and additional revenues to help scale up the industry in the absence of a sufficiently high price on carbon or regulatory requirements for carbon capture. However, while products such as concrete and plastics provide much longer-term—or even essentially permanent—sequestration, other uses, such as synfuels, release sequestered CO2 when combusted, just like other carbon-neutral biofuels. Markets for utilization resulting in permanent storage are also very limited in scale, compared to the scope of the challenge; a Nature Climate Change study projects that less than 5 percent of the carbon capture required to meet the Paris Agreement targets can be sequestered permanently via utilization, underscoring the need for large-scale geologic storage as well.

Regardless of the scale of its ultimate role as a source of firm zero-emission electricity generation globally, CCUS is an essential technology for the decarbonization of industrial end-uses. In developing countries with relatively young fleets of fossil fuel-fired power plants, CCUS may be the most important firm zero-carbon technology, given the need to prevent these assets from becoming stranded decades before the end of their useful lives. Thus, virtually any country seeking to achieve long-term emission reductions should consider policy steps to scale up capture facilities as well as the transportation and storage infrastructure required to support them.

CCUS Policy Recommendations

Research, Development, and Demonstration

Robust RD&D funding for CCUS can help bring down the costs of both proven and emerging capture technologies, as well as prove the viability of new utilization pathways. Key areas for funding include front-end engineering design (FEED) studies, increased R&D focus on the capture of emissions from industry and natural gas-fired generation (instead of the traditional focus on coal), and pilot and demonstration projects of next generation technologies—particularly those, such as oxy-fuel combustion approaches, that require construction of integrated greenfield facilities. Funding can also support the development and commercialization of products that utilize captured carbon, such as cement or algae-based bioproducts.

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Reducing Up-Front Costs

Similar to other early-stage clean energy technologies, CCUS is capital intensive, and policies that bring down its up-front costs have a central role to play in accelerating deployment. These can also reduce costs for CCUS equipment by incentivizing deployment at larger-scale facilities, and through supporting the development of modular, standardized system components. Suitable policy mechanisms may include low-interest loans, loan guarantees, accelerated depreciation, and tax-exempt private activity bonds to reduce interest rates and cost of capital. Grants and investment tax credits can be used to reduce the total cost of projects.

Because the cost of carbon capture increases with lower flue gas concentrations of CO2, support for capital costs should be tailored to some extent for different applications, contexts, and policy goals. For example, higher levels of support could be appropriate for retrofits on natural gas and bioenergy power plants, compared to coal in markets where coal plants are nearing their end of useful life and are uncompetitive in the market (e.g., the United States), or in regions with near-term goals for phasing out coal entirely. Even higher levels of support are likely justified for greenfield integrated CCUS plant designs when required for transformational approaches.

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Operating Support

Policies to improve the operational economics of plants and provide greater revenue certainty can also help secure project financing and reduce capital costs, and have the virtue of paying for performance of the specific goal of reducing carbon emissions. Appropriate types of support will vary by country and jurisdiction, but they can include tax credits, guaranteed payments such as feed-in tariffs, and/or contracts for difference mechanisms, and may be based on kilowatt-hours of CCUS-equipped power generation or tons of carbon captured and utilized or stored.

As with capital support measures, operating support should be sensitive to different applications and policy goals. For example, incentives that reward volumes of carbon stored (such as the 45Q tax credit in the U.S.) will provide greater incentives to CCUS deployment in the coal sector, compared to the natural gas sector, whereas natural gas may be advantaged by incentives for power generation in markets like the U.S., where gas is more competitive than coal. Eligibility for these incentives may also be tailored to prioritize sectors with the greatest long-term importance for emission reductions, for example, industrial uses and BECCS.

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Government Procurement of CCU Products

The operating economics of carbon capture can also be improved by developing markets for products that utilize captured carbon. Government procurement commitments to preferentially purchase these products can prove their viability and provide a significant source of demand in many cases, such as carbon-sequestering cement for public works projects or synfuels produced from hydrogen and captured CO2 for military aviation fuel requirements. As a first step toward procurement commitments, agencies can begin partnering with producers of carbon-utilizing products to study, test, and demonstrate their feasibility.

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Support for Infrastructure Hubs

The economics of CO2 transportation and storage infrastructure can be improved by increasing their utilization rates through the installation of CCUS equipment at a variety of sources in a given area. Industrial facilities and power plants are often built in close proximity due to shared fossil fuel feedstocks, and they may also be located near suitable storage sites at depleted oil and gas wells.

Grants or other types of financing support for the design and construction of common-use infrastructure at designated hubs can improve their economics as well as the economics of associated CCUS deployment, helping these projects secure financing. The deployment of CCUS at multiple facilities in one area can also serve economic development and political goals by bringing new investment to industrial and/or fossil fuel-producing regions and demonstrating the potential of this technology to enable them to participate in the clean energy transition.

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Employees work on pipes carrying liquid CO2 at the Black Pump power station run by European power company Vattenfall near Berlin on Sept. 7, 2008.MICHAEL URBAN/DDP/AFP VIA GETTY IMAGES

Advanced Nuclear: A Safer and More Scalable Nuclear Renaissance?

Nuclear reactors account for 18 percent of the world’s zero-emission power today and have avoided 55 gigatons (Gt) of CO2 emissions over the past 50 years, according to the IEA, making it one of the largest and longest-tenured climate change solutions. However, despite the growing urgency of the climate challenge, the global nuclear fleet is shrinking. In 2019, 5.5 gigawatts (GW) of new nuclear capacity were brought online, and 9.4 GW were retired, with 13 reactors permanently shut down in Japan, the United States, Switzerland, Germany, South Korea, Russia, Sweden, and Taiwan—just six of which were at least 40 years old and at the end of their useful lives. Of the 60.5 GW of nuclear capacity under construction, over half is concentrated in China, Russia, South Korea, India, and the United Arab Emirates.

Nuclear reactors account for 18 percent of the world’s zero-emission power today and have avoided 55 gigatons (Gt) of CO2 emissions over the past 50 years, according to the IEA, making it one of the largest and longest-tenured climate change solutions. There are several reasons for this downward trajectory for conventional nuclear power in most global markets. Meltdowns at the Fukushima Daiichi reactor in Japan as a result of an earthquake and a tsunami in 2011 gave fresh life to the safety concerns that have surrounded this technology following the 1957 Sellafield and 1979 Three Mile Island incidents, despite the fact that the health and safety impacts of the incident were ultimately minimal. Japan responded by temporarily shutting down all of its nuclear power plants, only a few of which have been brought back online, and Germany, Belgium, Spain, and Switzerland committed to begin phasing out nuclear power entirely.

A growing number of operating nuclear plants are also being retired for economic reasons in countries with competitive power markets as they struggle to compete with lower-cost—and often, subsidized—wind and solar power, as well as low-cost natural gas in some cases (e.g., the U.S.). Finally, in contrast to steadily falling costs for renewables, construction costs for new nuclear plants are rising, with recent projects in the U.S., France, the U.K., and Finland suffering severe escalations in costs and delays that have caused some projects to be abandoned.

In most cases, the zero-emission power from these plants is being replaced by coal- or natural gas-fired electricity, undermining climate goals. In Germany, 11 of the country’s 17 nuclear plants have been shut down in the past decade, resulting in a 5 percent increase in carbon emissions and an estimated 1,100 deaths per year from additional harmful local pollutants. As discussed earlier in this report, the loss of firm zero-emission resources raises the costs of achieving future emission-reduction targets. To combat this trend, there has been growing interest in radically different approaches to the design and deployment of nuclear power generation that seek to address today’s political and economic headwinds and return the industry to a growth trajectory.

Advanced Nuclear Technology Pathways

Advanced nuclear reactor technologies vary in design, but they all address the challenges faced by traditional nuclear plants in various ways. They are assembled primarily from prefabricated components, and many can be deployed in modular increments of megawatts (MW) or less, offering the potential to reduce capital costs and accelerate deployment compared to the site-specific design and construction processes required for traditional gigawatt-scale facilities. In contrast to current plants, which must run more or less constantly to operate efficiently, most advanced nuclear designs allow plants to ramp generation up and down more quickly, making them suitably flexible sources of power to support the variable wind and solar generators that are likely to provide the bulk of power on a decarbonized grid. All incorporate a variety of passive or inherent safety features that avoid relying on active controls, operational interventions, or backup AC power in the event of a malfunction, simplifying operations and potentially mitigating public concerns that have persisted despite the exemplary safety records of existing plants.

Some advanced nuclear reactor designs could also provide unique benefits as compared to existing plants. Reactors operating at higher temperatures than conventional reactors may be suitable for providing industrial process heat for applications such as hydrogen or ammonia production, offering an additional revenue stream to improve plant economics. Similarly, hybrid designs that combine advanced nuclear plants with desalination facilities have also been proposed for water-poor countries like Saudi Arabia, which would maximize operational and economic efficiencies by providing power generation to the grid when needed, and to a desalination plant to produce fresh water at other times. Since most of these advanced reactors can be deployed at much smaller sizes than traditional plants, they have the potential to be deployed by smaller utilities, in remote or off-grid locations, or at critical facilities such as military bases.

According to a recent MIT study, there are three main types of advanced reactors that are sufficiently mature to have realistic potential for commercialization by 2030: small modular reactors based on Generation III light water reactor (LWR) designs, and sodium fast reactors and modular high-temperature gas-cooled reactors that are in the Generation IV family. These types can be categorized by the type of coolant used to transfer heat from the reactor to generating units, which determines a variety of plant design features as well as the neutron spectrum of the fuel used, which is determined by the presence or absence of different types of moderators that slow down neutrons to produce fission reactions.

  • Light water small modular reactors (SMRs) use water as a coolant and operate on the thermal neutron spectrum, using conventional uranium fuel and water as a moderator. These SMRs leverage decades of operating experience with the large-scale Generation III reactor technology they are based on, but they use smaller and simpler configurations with passive safety features that require little or no backup power and provide long-term core cooling in case of an accident. SMR designs have been proven in the field for naval applications, and in 2019 Russia’s 70 MW Akademik Lomonosov floating nuclear power plant was connected to the power grid and subsequently became the first SMR power plant to begin commercial operations in the world.

    According to the International Atomic Energy Agency (IAEA), there are 25 land-based SMR designs based on LWR technology in various stages of development across 12 countries, including the U.S., the U.K., Canada, France, Russia, China, Japan, and South Korea. Construction of the China National Nuclear Corporation’s (CNNC) first APC100 plant, a 125 MW SMR designed to also provide heat for desalination or other purposes, was approved to begin in June 2021 with operations expected in 2025. In the U.S., a 60 MW light-water reactor from startup NuScale Power became the first SMR to complete a Nuclear Regulatory Commission (NRC) safety evaluation—putting it on track for full certification by August 2021—and planned deployment in a 12-module plant at the Idaho National Laboratory, with operations expected in 2029.

  • Modular high-temperature gas-cooled reactors (HTGRs) use helium gas as a coolant and a solid graphite moderator for thermal neutron spectrum operation, and utilize robust TRISO fuel that can withstand extreme temperatures and will not melt down in a reactor. TRISO stands for “tri-structural isotropic particle fuel” and consists of poppy seed-sized kernels of uranium, carbon, and oxygen encapsulated in layers of carbon- and ceramic-based materials that essentially act as a built-in containment system. These are fabricated into cylindrical pellets or round “pebbles,” which slowly circulate through the core, allowing for refueling while the plant is still online in a process that is ‘like a gumball machine.’ These reactors typically yield outlet temperatures of 700°C to 850°C, or up to 950°C for very high temperature reactor (VHTR) variations, making them suitable for a range of industrial process heat applications.

    According to IAEA, there are 11 modular HTGR plant designs in various stages of development worldwide, including test reactors that have been in operation in Japan and China for over 20 years. China’s HTR-PM plant, which began construction in 2012, is on track to become the world’s first commercial-scale HTGR plant to begin operations later in 2021, and the country’s CNNC began shipping its first batches of pebble fuel in January of 2021. In October of 2020, startup X-Energy was selected as one of the first awardees of the U.S. Department of Energy’s new Advanced Reactor Demonstration Program to build a four-unit demonstration project for its 76 MW Xe-100 HTGR. X-Energy was also selected by the U.S. Department of Defense in early 2021 to design a transportable microreactor of 1 to 5 MW in size and capable of operating within three days of delivery for use in the field.

  • Sodium-cooled fast reactors (SFRs) use liquid metal sodium as a coolant, which provides superior heat-removal capabilities and allows the plant to operate on the fast neutron spectrum without a moderator. This results in very high power density and the use of different types of fuels, including metal alloy fuels consisting of steel-clad uranium and zirconium as well as mixed oxide fuels (MOX) that include reprocessed plutonium and depleted uranium. This enables SFRs to recycle fuel from current nuclear plants as well as military sources, reducing fuel requirements and waste disposal issues compared to conventional plants.

    GE Hitachi and TerraPower, a startup founded by Bill Gates in 2008, were selected to receive funding from the DOE Advanced Reactor Demonstration program in 2020 to build the world’s first commercial scale SFR reactor. The Natrium plant design will pair a 345 MW SFR reactor with a molten salt energy storage system that will capture waste heat and allow it to be released to boost output to a total of 500 MW for several hours during periods of peak demand. In June of 2021, TerraPower announced that it would build this demonstration facility at the site of a retiring coal plant in Wyoming, with the specific site still being decided among several candidates.

Selected Advanced Nuclear Demonstration Projects

Hover over each map location for more information

  • Light Water Small Modular Reactors (SMR)Light Water Small Modular Reactors (SMR)
  • Modular High-Temperature Gas-Cooled Reactors (HTGR)Modular High-Temperature Gas-Cooled Reactors (HTGR)
  • Sodium-Cooled Fast Reactors (SFR)Sodium-Cooled Fast Reactors (SFR)
Selected Advanced Nuclear Demonstration Projects map

Light Water Small Modular Reactors (SMR) Pevek, Russia

  • Type: Light Water Small Modular Reactors (SMR)
  • The project: Akademic Lomonosov
  • Capacity: 70 megawatts
  • Status: Operating

Light Water Small Modular Reactors (SMR) Yakutia, Russia

  • Type: Light Water Small Modular Reactors (SMR)
  • The project: Rosatom RITM-200
  • Capacity: 175 megawatts
  • Status: Pre-licensing

Light Water Small Modular Reactors (SMR) Buenos Aires, Argentina

  • Type: Light Water Small Modular Reactors (SMR)
  • The project: CAREM-25
  • Capacity: 25 megawatts
  • Status: Under construction

Light Water Small Modular Reactors (SMR) Changjiang, China

  • Type: Light Water Small Modular Reactors (SMR)
  • The project: ACP-100
  • Capacity: 125 megawatts
  • Status: Under construction

Modular High-Temperature Gas-Cooled Reactors (HTGR) Shandong, China

  • Type: Modular High-Temperature Gas-Cooled Reactors (HTGR)
  • The project: HTR-PM
  • Capacity: 210 megawatts
  • Status: Under construction

Modular High-Temperature Gas-Cooled Reactors (HTGR) TBD, United States

  • Type: Modular High-Temperature Gas-Cooled Reactors (HTGR)
  • The project: X-Energy XE-100
  • Capacity: 80 megawatts
  • Status: Pre-licensing

Sodium-Cooled Fast Reactors (SFR) TBD, United States

  • Type: Sodium-Cooled Fast Reactors (SFR)
  • The project: GE Hitatchi BWRX300
  • Capacity: 300 megawatts
  • Status: Pre-licensing

Light Water Small Modular Reactors (SMR) Idaho National Laboratory, United States

  • Type: Light Water Small Modular Reactors (SMR)
  • The project: NuScale Power Module
  • Capacity: 60 megawatts
  • Status: Pre-licensing

Sources: NS Energy, World Nuclear News, Nuclear Engineering International, X-Energy, US DOE Office of Nuclear Energy, Wilmington Biz, Power Engineering International, Rolls-Royce

In general, these advanced nuclear reactor designs are all based on technologies that are proven to varying degrees and are on track to see commercial-scale deployments by the end of the decade. Moreover, their reliance on simpler designs and standardized components offers potential for much faster deployment, at a greater range of scales and in a wider variety of contexts than traditional nuclear plants. Based on estimates for commercial-scale first-of-a-kind facilities for these technologies, MIT estimates the future levelized costs of “next-of-a-kind” facilities to be between $100 and $120 per MWh, similar to today’s coal or gas plants equipped with CCS. As with the other firm zero-emission technologies discussed in this report, their anticipated commercialization around the 2030 time frame is likely to align with steeply increasing costs of decarbonizing the grid with variable resources alone.

At a minimum, advanced nuclear technologies are likely to play an important role in specific applications, such as military bases, islands, or other markets where geographic constraints limit the viability of renewables. Alternately, they may emerge as the most robustly applicable and affordable solution for a reliable baseload generation globally, thanks to factory manufacturing processes and inherently safe modular plant designs. While a relatively limited number of countries have the nuclear expertise and resources to develop these technologies, the potential advantages for decarbonization as well as export opportunities may merit policy support to accelerate their development and deployment.

Advanced Nuclear Policy Recommendations

Research, Development, and Demonstration

Governments can reduce the costs and risks associated with developing advanced nuclear technologies in a variety of ways. Grants and other cost-sharing arrangements can play an important role in supporting new technologies throughout their lifecycles, from early prototypes to full-scale demonstration plants. Because R&D, licensing, and construction timelines for these first-of-a-kind projects have typically spanned a decade or more, these programs should be of similar (long) duration, with technical milestones for additional funding throughout the process. Access to government nuclear R&D facilities, such as national laboratories or reactor parks built to accommodate testing of diverse reactor concepts, can also play a role in accelerating early-stage R&D.

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Deployment Incentives

Nuclear power projects of any scale are capital intensive—often cost-prohibitively so—and policy support for the first generation of commercial facilities of all of these advanced nuclear approaches will be vital for deployments through 2030 at least. This support may take a variety of forms, including grants, loan guarantees to reduce borrowing costs, and advanced cost-recovery and regulatory asset base (RAB) models that provide government-backed cost-recovery mechanisms. Risk insurance programs, such as the standby support model in the U.S. that provide cost coverage for construction delays on new plant designs, can also help developers access lower-cost sources of capital.

To avoid wasting resources and potentially causing political blowback, as in the case of multi-billion-dollar cost overruns for conventional nuclear plants in the U.S. that have recently used advanced cost-recovery approaches, recipients of any of these types of support must be chosen carefully for reasonably proven, simple-to-deploy designs that can be expected to achieve the construction cost-reduction goals shared by all advanced nuclear technologies.

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Operating Support

In countries with competitive power sectors, another pathway for incentivizing advanced nuclear development is providing guaranteed offtake or support for operating revenues, which may not be sufficient under current market conditions. Policies such as production tax credits, contracts for difference (an approach where generators are compensated if power prices fall below a specified level, or pay the government when prices are higher, effectively locking in prices), and feed-in tariffs that have helped renewable power technologies scale up are all broadly applicable for advanced nuclear, as they are included in clean energy purchase requirements for utilities based on successful renewable portfolio standard (RPS)-type policies.

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Government Procurement

Power-purchasing agreements with government off-takers offer another source of guaranteed revenues and may be justified for military bases and other remote facilities that require firm on-site zero-emission power. Alternatively, some advanced reactor designs capable of producing heat for industrial processes may benefit from government-backed procurement contracts for associated products other than zero-carbon electricity, such as fresh water from integrated desalination facilities or synthetic aviation fuels.

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Regulatory Reforms and International Collaboration

New advanced reactor designs are inherently safer than previous generations of nuclear plants, as they eliminate many of their risks through design features. Regulatory licensing regimes should be reformed to be more flexible, allowing unnecessary steps to be eliminated and potential safety issues to be evaluated in appropriate ways for each reactor design. Tailored pathways for advanced reactor prototypes, as well as staged licensing processes that can certify designs incrementally as each aspect is developed, can also help reduce risks during the RD&D process.

Because the fundamental basis of assessing reactor safety is essentially uniform across countries with nuclear power programs, many regulators around the world have adopted principles modeled after the IAEA as well as the U.S. NRC, albeit with local differences in requirements for certain aspects such as burden of proof of facilities’ safey. Because advanced reactor designs are standardized, factory-produced, and suitable for export, international collaboration to harmonize licensing processes across borders could significantly accelerate global deployment and market development.

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X Energy’s XE-100 pebble-bed, high-temperature gas-cooled reactor. X ENERGY

Unconventional Geothermal: The Renewable Firm Zero Solution

Unconventional geothermal approaches are in some ways the least proven firm zero emission generation solutions, but they may face the fewest political obstacles, because they harness renewable energy. Traditional geothermal power plants are essentially boutique resources: they generate 24/7 electricity by pumping steam from boiling water located in naturally occurring hydrothermal reservoirs located close to the earth’s surface. In regions lucky enough to have such easily accessible resources, typically near tectonically active regions such as the, the “Ring of Fire” including the western U.S., Mexico, Central America, Indonesia, the Philippines, and New Zealand, along with Turkey, Kenya, Iceland, and Italy—geothermal has provided reliable, low-cost renewable power for decades.

Ironically, advances in drilling and related technologies developed for oil and gas fracking applications, along with a rising need for firm zero-carbon generation, have led to what may be the biggest wave of innovation in the industry since the first geothermal plants came online in Italy at the dawn of the 20th century. However, conventional geothermal is not an option for the vast majority of the world, and the exponential growth of widely deployable wind and solar resources over the past decade has rendered it a vanishingly small portion of the renewable fleet. Today, geothermal accounts for less than 1 percent of renewable power capacity globally and 1.3 percent of total renewable power generation, according to the International Renewable Energy Agency (IRENA), and global capacity grew just 3 percent in 2019, according to the IEA—far less than the 10 percent annual growth through 2030 required to meet the agency’s Sustainable Development Scenario.

Ironically, advances in drilling and related technologies developed for oil and gas fracking applications, along with a rising need for firm zero-carbon generation, have led to what may be the biggest wave of innovation in the industry since the first geothermal plants came online in Italy at the dawn of the 20th century. New approaches to harnessing the essentially limitless potential of “the sun beneath our feet”—so called because the earth’s core generates temperatures comparable to the sun itself, flowing 30 terawatts (TW) of heat to the surface—seek to transform geothermal from a boutique resource into a globally deployable renewable power technology on par with wind and solar in terms of near-universal applicability.

Unconventional Geothermal Pathways

While the terminology surrounding these potentially transformational new approaches is still evolving (and potentially confusing), including enhanced geothermal, engineered geothermal, and advanced geothermal among others, they can loosely be categorized as “unconventional,” because they all seek to tap into subsurface heat resources that lack the usual fluid and/or geological characteristics of today’s geothermal plants. These unconventional geothermal approaches also all offer an opportunity for fossil fuel companies to leverage their unique drilling expertise and R&D resources in service of the energy transition, potentially creating new political alignments in support of climate action.

  • Enhanced Geothermal Systems (EGS), sometimes referred to as “engineered geothermal systems” or “hot dry rock” (HDR) geothermal, are the most relatively established unconventional geothermal technology, with the U.S. Department of Energy funding research into this approach as far back as the 1970s. EGS approaches essentially seek to create man-made hydrothermal reservoirs similar to the naturally occurring reservoirs used by conventional geothermal plants by drilling wells in dry rock and engineering fracture networks capable of circulating water at sufficient temperatures (typically 150°C or greater) for power generation. In the past decade, advances across necessary technologies for drilling, reservoir stimulation, and reservoir modeling and management that were first developed for the fracking industry have helped to spark new interest in EGS applications that will also benefit from them.

    EGS have been demonstrated to varying degrees of success at sites of conventional geothermal projects, also referred to as “in-field” EGS, where this technique has been proven capable of improving overall power generation through increasing the permeability (and thus output) of existing reservoirs. These demonstrations have also highlighted important differences between oil and gas fracking and EGS. Whereas the former require only a limited reservoir volume for relatively low-volume production wells over a short period of time, a successful EGS project requires sustained circulation of water at high flow rates over the entire life of a project, requiring much larger reservoirs and more carefully engineered fracture networks that minimize subsurface water losses and sustain sufficient levels of heat recovery for power generation.

    Once continued experience and innovation enable the more reliable development of EGS systems, the GeoVision report from the U.S. Department of Energy expects these techniques to be applied to gradually more challenging projects: first at “in-field” sites and currently sub-commercial wells that can be connected to existing conventional reservoirs to boost their production, then at well-characterized “near-field” sites adjacent to conventional resources and, ultimately, at previously unexplored “deep” EGS applications that realize the potential of this approach to bring the benefits of geothermal power to completely new regions. The GeoVision study estimates that these resources could unlock over 5 TW of generating capacity in the U.S. alone, or about five times the current combined capacity of all of the power plants in the country.

    With optimistic assumptions for technology advancements, EGS has the capacity to become a cost-effective source of firm zero-emission power. The National Renewable Energy Laboratory’s most recent Annual Technology Baseline for geothermal pegs the levelized costs of EGS electricity in 2030 at $50 to $80 per MWh in its advanced technology scenario based on the GeoVision report, depending on whether plants exploit near-field or deep geothermal resources. This is less expensive than estimates for CCS with natural gas and advanced nuclear technologies from other studies cited above, although it similarly remains higher than present-day wind and solar.

  • Super-hot-rock (SHR) geothermal, sometimes referred to as “supercritical” or “deep EGS,” extends the EGS approach even deeper below the surface to tap into sufficiently high temperatures and pressures (over 370°C and 220 bar) for circulated water to change state and become supercritical—a phase that is neither liquid nor gas and holds as much as 10 times the amount of energy per unit of mass compared to cooler water utilized in conventional geothermal projects. This supercritical water can then be converted to electricity at a correspondingly higher efficiency. Whereas an EGS plant harnessing temperatures of 200°C would generate about 5 MW of power, a supercritical plant at 400°C could yield 50 MW. Levelized costs of power generation would also come down—AltaRock, a U.S. startup funded by the ARPA-E program of the U.S. Department of Energy, estimates levelized costs for supercritical systems as nearly half those of EGS systems operating at standard temperatures.

    The tantalizing potential of SHR geothermal faces significant hurdles to surmount before it becomes a reality. In addition to the existing challenges of developing an EGS plant at lower depths and temperatures and sustaining operations over the long term, supercritical projects must be engineered and developed under even more challenging circumstances. This will require new casings, cements, and other materials capable of operating at higher heat levels than oil and gas drilling, as well as better understanding of water and brine chemistry at these temperatures. As such, research into this area is more limited than for EGS to date, with the Iceland Deep Drilling Project as one prominent example.

Despite the vast potential of EGS and SHR approaches to serve as a renewable firm zero-carbon electricity source virtually anywhere in the world, both approaches may face obstacles due to both real and imagined environmental issues associated with fracking. Backlash against fracking for oil and gas due to their role in boosting fossil fuels and perceived risks to water supplies from the fluids used to fracture wells has led to a proliferation of fracking bans in a variety of countries as well as states and provinces in North America. While EGS and SHR systems offer a potentially very important climate solution, biases against this drilling approach will need to be navigated in these jurisdictions. More concretely, EGS and SHR projects must manage potential emissions from bringing gases up to the surface, and they must use care to avoid induced seismicity issues that have cropped up in the context of fracking disposal wells.

  • Advanced geothermal, sometimes referred to more descriptively as “closed-loop geothermal,” represents a fundamentally different approach as compared to EGS and SHR. Instead of pumping from a reservoir of boiling (or supercritical) water to create steam for power generation, this approach continuously circulates working fluids through long systems of sealed pipes and boreholes underground, extracting heat through conduction. The principle can be likened to a radiator and is similar to closed-loop geothermal heat pumps that are used to heat buildings. By harnessing horizontal drilling techniques honed in fracking applications to create deeper and longer closed-loop systems, sufficient heat can be generated to produce steam and electricity.

    Horizontal drilling at required temperatures of 150°C or greater in hard rock is a challenge for today’s equipment, which was developed for less-demanding oil and gas applications. However, if technology improvements allow this technique to be mastered, advanced geothermal promises to unlock EGS’s potential of enabling geothermal power to be harnessed anywhere while also avoiding some of its technical and political challenges, since it does not require the creation of reservoirs through fracking. The promise of this “best of both worlds” approach is enormous, and the Canadian startup Eavor—which recently secured investments from BP and Shell’s venture capital arms—is building its first commercial-scale facility in Germany and believes that it will be able to generate power at $50/MWh by the end of the decade.

Recent and Active Unconventional Geothermal Demonstration Projects

Hover over each map location for more information

  • Enhanced Geothermal Systems (EGS) Enhanced Geothermal Systems (EGS)
  • Super-Hot-Rock (SHR)Super-Hot-Rock (SHR)
  • Closed Loop (CL)Closed Loop (CL)
Recent and Active Unconventional Geothermal Demonstration Projects map

Enhanced Geothermal Systems (EGS) Qiabuqia, China

  • Type: Enhanced Geothermal Systems (EGS)
  • The project: Jilin University and China Geological Survey
  • Status: Research

Enhanced Geothermal Systems (EGS) Saxony, Germany

  • Type: Enhanced Geothermal Systems (EGS)
  • The project: Roter Kamm developed by the Federal Institute for Geosciences and Natural Resources
  • Status: Research

Super-Hot-Rock (SHR) Reykjanes, Iceland

  • Type: Super-Hot-Rock (SHR)
  • The project: Iceland Deep Drilling Project (IDDP) developed by the Deep Vision consortium headed by the National Energy Authority of Iceland
  • Status: Testing

Super-Hot-Rock (SHR) Vendenheim, France

  • Type: Super-Hot-Rock (SHR)
  • The project: Developed by Fonroche Géothermie
  • Status: Testing

Enhanced Geothermal Systems (EGS) Cornwall, United Kingdom

  • Type: Enhanced Geothermal System (EGS)
  • The project: United Downs developed by Geothermal Engineering Limited
  • Status: Testing

Enhanced Geothermal Systems (EGS) Cornwall, United Kingdom

  • Type: Enhanced Geothermal System (EGS)
  • The project: Eden Project developed by the Eden Geothermal Ltd
  • Status: Testing

Enhanced Geothermal Systems (EGS) Otaniemi, Finland

  • Type: Enhanced Geothermal System (EGS)
  • The project: St1 Otaniemi developed by St1
  • Status: Testing

Enhanced Geothermal Systems (EGS) Utah, United States

  • Type: Enhanced Geothermal System (EGS)
  • The project: FORGE developed by the U.S. Department of Energy
  • Status: Testing

Closed Loop (CL) California, United States

  • Type: Closed Loop (CL)
  • The project: GreenLoop developed by GreenFire Energy
  • Status: Low-temperature demonstration

Closed Loop (CL) Alberta, Canada

  • Type: Closed Loop (CL)
  • The project: Eavor-Lite developed by Eavor
  • Status: Low-temperature demonstration

Sources: Renewable Energy, ThinkGeoEnergy, U.S. DOE, st1, Eavor

Like advanced nuclear technologies, unconventional geothermal technologies can also provide useful heat for a variety of purposes. While the heat provided by geothermal resources is not capable of supplying the industrial applications that can be served by high-temperature advanced nuclear designs, it is well suited for space heating as well as low-temperature applications such as greenhouses (or maturing rum). Conventional geothermal resources have a long track record of this, via ground-source heat pumps for individual buildings as well as district heating systems that send heat through a network of pipes for use across an entire town or region. For example, Iceland has been using geothermal for district heating since the 1950s, and 90 percent of its citizens are now served by this resource. Unconventional geothermal technologies would allow these types of applications to be potentially deployed virtually everywhere in the world, offering an important pathway for decarbonizing the challenging end-use sector of building heat at scale.

While these approaches have not been proven to the same extent as CCUS or advanced nuclear technologies based on Generation III plants, their potential to provide a commercially viable and renewable source of zero-carbon firm generation and heating in the 2030 timeframe merits similar types and levels of policy support. Because unconventional geothermal requires the evaluation and use of subsurface resources, including the injection of working fluids in the cases of EGS and SHR approaches, development and deployment can be accelerated through similar regulatory actions as CCUS, along with technology development, demonstration, and deployment support similar to Generation IV nuclear plants.

Unconventional Geothermal Policy Recommendations

Research, Development, and Demonstration

Support for RD&D will be critical to accelerating all of these new approaches to geothermal energy, and it merits funding for research as well as pilot-scale demonstration projects. RD&D support is particularly important for SHR approaches, which require drilling at high temperatures and pressures farther beneath the surface, as well as closed-loop applications, which require improved horizontal drilling capabilities.

Meeting the unique performance requirements for these applications can leverage technologies, expertise, and other resources from oil and gas R&D programs, which can play roles in helping researchers and other workers in this industry bring their skill sets to geothermal. Oil and gas companies could also be provided with grants or incentives, such as tax credits or loan guarantees for investments in improved drilling technologies suitable for unconventional geothermal resources.

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Capital Incentives

Deployment of first-of-a-kind, commercial-scale unconventional geothermal projects will likely require support in order to reduce capital costs. This support should be tailored to the different maturity levels of these approaches and different project types. EGS systems have been successfully demonstrated in in-field applications, which could potentially be supported by loans, loan guarantees, and tax credits, but less-proven deep EGS applications may require grants. Supercritical and closed-loop geothermal techniques are not as far along in their development and thus may be unsuitable for financing support such as loans or loan guarantees, but their significant advantages in energy production and siting, respectively, may merit higher levels of grant funding.

Even considering their potential for widespread deployment geographically, the challenges, and thus costs, of deploying early-stage EGS and SHR systems in particular will be dependent on site-specific geology. Accordingly, programs should be designed to support multiple commercial-scale facilities in different regions to help establish the widespread viability of these approaches. EGS and SHR projects can also benefit from incentives that reduce exploration and drilling risks, such as government-provided insurance, risk-sharing facilities, and tax write-offs for failed wells.

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Operating Support

Like conventional geothermal projects, and similar to oil and gas fracking, unconventional geothermal faces a variety of surface and subsurface regulatory requirements to ensure that exploration, resource confirmation, drilling, and fluid injections are all conducted safely. However, the relatively limited development of geothermal to date can lead to fragmented regulatory processes with separate permitting steps for each phase of a project. Most regulatory agencies also have relatively fewer permitting resources to devote to geothermal than to oil and gas, resulting in backlogs and delays that extend construction timelines and increase financing costs. This challenge could become even greater as unconventional geothermal technologies allow for deployment in regions lacking experience with traditional geothermal plants.

A variety of steps can be taken to reduce these challenges and accelerate project development, which will be essential to deploying these resources at a scale commensurate with the urgency of the climate challenge. Potential improvements vary by jurisdiction but could include coordination of relevant permitting authorities, additional resources for dedicated geothermal experts, and a consolidation of permitting steps and/or providing categorical exclusions from certain requirements when possible to do so safely. In the U.S. context, the GeoVision report estimates that such steps to improve regulatory timelines could reduce the time required to develop EGS projects by five years. Because they require much deeper wells, SHR projects may require additional regulatory attention, and resources should also be devoted to assessing permitting requirements as this technology advances.

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Regulatory Streamlining

Power-purchasing agreements with government off-takers offer another source of guaranteed revenues and may be justified for military bases and other remote facilities that require firm on-site zero-emission power. Alternatively, some advanced reactor designs capable of producing heat for industrial processes may benefit from government-backed procurement contracts for associated products other than zero-carbon electricity, such as fresh water from integrated desalination facilities or synthetic aviation fuels.

Hover over box and scroll for more developments

Regulatory Reforms and International Collaboration

New advanced reactor designs are inherently safer than previous generations of nuclear plants, as they eliminate many of their risks through design features. Regulatory licensing regimes should be reformed to be more flexible, allowing unnecessary steps to be eliminated and potential safety issues to be evaluated in appropriate ways for each reactor design. Tailored pathways for advanced reactor prototypes, as well as staged licensing processes that can certify designs incrementally as each aspect is developed, can also help reduce risks during the RD&D process.

Because the fundamental basis of assessing reactor safety is essentially uniform across countries with nuclear power programs, many regulators around the world have adopted principles modeled after the IAEA as well as the U.S. NRC, albeit with local differences in requirements for certain aspects such as burden of proof of facilities’ safey. Because advanced reactor designs are standardized, factory-produced, and suitable for export, international collaboration to harmonize licensing processes across borders could significantly accelerate global deployment and market development.

Hover over box and scroll for more developments

A geothermal plant outside Myvatn, Iceland, on April 12, 2017. LOIC VENANCE/AFP VIA GETTY IMAGES

Leading the Way to a Reliable, Affordable, Deeply Decarbonized Grid

‎All countries with emissions-reduction goals ‎stand to gain from the commercialization of some or all of these firm zero-emission technologies. CCUS will be essential everywhere for decarbonizing industry as well as abating carbon emissions from existing fossil fuel plants, which may be decades from the end of their useful lives. And while it is a relatively mature technology, further cost reductions from scaling up and the development of new end-use markets for captured carbon promise to accelerate its deployment, and novel approaches such as oxy-fuel combustion could make CCUS for firm zero-emission power more efficient and eliminate other non-carbon emissions that are harmful to human health.

Advanced nuclear and unconventional geothermal technologies are less proven than CCUS but offer potential for similar cost reductions in achieving deep decarbonization goals, the prospect of eliminating all emissions, and the ability to be deployed at different scales virtually anywhere on (or off) the grid instead of being tied to existing fossil fuel development. Advanced nuclear plants in particular may also offer significant economic opportunities from exports if they succeed in their ambition to create truly modular, factory-built power plant designs. And while specific political contexts vary significantly, these technologies may face an easier path to securing policy support in many cases, since the ties of CCUS to the fossil fuel industry lead to skepticism or outright opposition from many climate activists.

Of course, given the history of nuclear power and the dependence of EGS and SHR unconventional geothermal approaches on fracking, these technologies also face uncertain politics in some jurisdictions despite their clear value for decarbonization strategies. Thus, in addition to the similar roles that all three could play in decarbonizing the electricity grid, all may require outreach and coordination with environmental groups to broaden public acceptance. These efforts would be aided enormously in almost every case by securing buy-in from conservatives and fossil fuel companies who have been the sources of obstruction for climate action in the past.

Beyond this takeaway, there are other shared, overarching themes for policymakers interested in accelerating the development of these firm zero-emission technologies:

  • Long-term RD&D Programs: Most of these technology applications are ready for pilot or demonstration-scale projects, and government RD&D support can make a decisive difference in getting them built. While these are hardly the only clean energy technologies that could benefit from an increase in RD&D, their capital-intensive nature and relatively long timelines required to develop first-of-a-kind projects make the availability of significant and sustained funding programs particularly important. When feasible, demonstration projects should be built as close to a commercial scale as possible to shorten time to market and improve subsequent bankability.
  • Level Playing Field with Wind and Solar: To date, government support for zero-emission generation has gone primarily or even exclusively to wind and solar technologies. Including emerging firm zero-emission technologies under these or similar programs, such as renewable (or clean) energy standards or other purchasing mandates, financing assistance or grants to reduce up-front costs, and/or various revenue-enhancement mechanisms, such as production tax credits or auctions, can help make commercial-scale projects bankable as well as help earlier-stage technology companies attract capital for RD&D. A meaningful carbon price would be the ideal technology-neutral approach for leveling the playing field and sending a long-term signal to investors, and it would benefit CCUS especially if applied to industry as well as power.
  • Leverage Non-Electricity End Uses: Beyond electricity, many of these technologies can serve other end uses. Advanced nuclear plants can provide high-temperature heat for desalination or hydrogen production, unconventional geothermal offers potential for district heat applications, and captured carbon can be utilized in a growing range of products, including cement and synthetic aviation fuels. Incentives for these end uses, or even direct government procurement, can provide opportunities for additional (or alternative) avenues for policy support. There may also be opportunities to expand technology as well as economic development benefits by co-locating these resources with off-takers in new or existing zero-emission industrial clusters, enabling shared infrastructure such as grid connections, pipeline, and storage facilities.
  • Differentiate Between Technologies and Applications: While all of the technology pathways and applications covered in this report are expected to be feasible to commercialize by 2030, there are significant differences among their trajectories and performance characteristics that may have relevance for policy goals. Generation III-based SMR and EGS are more developed than other advanced nuclear and unconventional geothermal technologies, respectively, and they may be more suitable for commercial-scale demonstrations than less-developed approaches that may require more R&D support. Similarly, oxy-fuel combustion CCUS and closed-loop geothermal technologies are less developed than other approaches, but they avoid the potential environmental issues associated with conventional CCUS and EGS projects.

The lion’s share of progress in decarbonizing the electricity sector over the next decade will almost certainly come from the continued deployment of today’s wind and solar technologies, which will inexorably lead to the shuttering of more and more aging fossil fueled power plants, and many nuclear plants, around the world. Decarbonizing beyond this point into the 2030s, however, will almost certainly require dispatchable, firm zero-emission resources ready to deploy at scale to replace the remaining fossil fueled fleet, or else this task will become vastly more expensive as well as politically challenging. Strategic, long-term policy frameworks to support these technologies today can play a critical role enabling this durable foundation for long-term international climate progress while also achieving economic development goals through new industrial development, and energy security goals through increased grid resilience.

By FP Analytics. Written by John Atkinson. Edited by Allison Carlson. Copyedited by David Johnstone. Development by Andrew Baughman and Atif Majeed. Art direction by Lori Kelley. Illustration by Nicolás Ortega for Foreign Policy.

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