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Fixed emission-free performance

Wind and solar energy resources have made incredible strides over the past decade as supportive interventions have resulted in massive expansions of these technologies and steep cost reductions that have made them an overwhelming choice for power generation investments. In 2019, renewable energies accounted for over 80 percent of newly installed capacity worldwide, over 90 percent of which came from wind and sun. The generation capacity from these resources has grown significantly, but still makes up a small proportion of actual generation, also because they only generate electricity when the wind is blowing and the sun is shining. According to the International Energy Agency (IEA), wind and sun together currently make up less than 10 percent of the global electricity mix.

Nevertheless, the share of electricity supply from these variable resources is growing rapidly, and they are proving to be adept at integrating them while maintaining reliability, even in areas where their share of the electricity mix is ​​relatively high. A recent study of over 40 modeling studies for the electricity sector showed broad agreement that the grid could be cost-effectively decarbonised by 50 to 70 percent through a combination of existing wind, solar and battery technologies as well as flexible demand technologies that can shift consumption to hours of the day in order to do justice to the variable offer.

However, these studies also found that achieving more ambitious goals for a zero-emission network can become much more technically demanding and also prohibitively expensive if network operators rely solely on these technologies. Lithium-ion batteries and flexible demand can compensate for the daily fluctuations in wind and sun, but they are unable to efficiently store electricity for days, weeks or months during prolonged or seasonal lulls such as heat waves. when the wind subsides for several days or winter months when the sun shines fewer hours. Models for wind and solar decarbonization scenarios rely heavily on a massive superstructure of wind and solar capacities to compensate for these seasonal fluctuations, as well as on the expansion of transmission networks on a continental level to connect wind and sun across time zones and regional weather patterns.

While it is possible that this challenge could be solved with the advent of long-term storage technologies, such as new battery chemistries or other physical or chemical storage concepts, these approaches are largely unproven and likely extremely expensive or even impossible to deploy at any given time Scale. These looming challenges become even more serious as we increasingly rely on the grid to decarbonise the transportation and cooling and heating needs of buildings, as “electrifying everyone” will increase overall consumption and the seasonality of demand.

Maintaining significant generation resources with operating characteristics similar to today's power plants – often referred to as "solid" or "disposable" resources because they can be ramped up and down at any time, would drastically reduce the likely costs of a deep decarbonization of the grid reduced by using a more diversified solution portfolio. However, continued reliance on undiminished fossil fuels is clearly incompatible with a zero-carbon future, and today's solid zero-carbon resources all face formidable barriers to increasing their share of the grid. Hydropower and geothermal resources have proven to be inexpensive solutions, but are geographically limited in their feasibility, and large-scale nuclear use has gone from "too cheap to measure" to "too expensive to build" in competitive markets (quite to mention the political challenges in some countries).

The most likely fixed emission-free electricity resources of the future combine established controllable generation technologies with radically new approaches to overcome these limitations. CO2 capture, use and storage can (almost) eliminate CO2 emissions from fossil fuel power plants; advanced nuclear approaches promise reductions in capital costs, construction schedules and safety concerns; and unconventional geothermal technologies could make it possible to tap the heat emanating from the earth's core anywhere in the world instead of just in tectonically active regions.

Unlike wind and solar, these technologies are largely pre-commercial and require significant public and private investments in research and development, demonstration and deployment. However, because they all use proven technologies, they each have the potential to be economically viable over the next decade and thus to play a crucial role in achieving the Paris Agreement goals for economic decarbonization by mid-century.

CCUS: An essential tool for the decarbonization of industry … and fossil fuels?

Carbon Capture, Use or Storage (CCUS), a broad category that combines Carbon Capture and Storage (CCS) and Carbon Capture and Use (CCU), is the most established and widely used of these potential candidates for a company with zero emissions of electricity. CCUS begins by capturing and capturing CO2 from the flue gas streams of a fossil fuel power plant or other industrial facility using a variety of chemical and physical processes. These captured emissions are then compressed and transported, typically via a pipeline, to either reach customers for use (e.g. a beverage carbonation plant) or for injection under pressure into suitable long-term reservoirs – mainly saline geological formations or depleted oil and gas wells. Essentially, this permanent geological storage brings the carbon that is created from burning fossil fuels back to where it came from.

The appeal of CCS is obvious. From a technical standpoint, it allows utilities to continue to build and rely on familiar technology to anchor the grid so that they can bypass the operational challenges and other feasibility risks of decarbonization with wind and solar alone. From an economic perspective, CCS devices can be retrofitted to existing facilities, promising the salvation of trillion-dollar assets that are currently threatened with stranding, including fossil-fuel power plants and oil, gas and coal reserves. It also translates into a potential political advantage for CCS, as it allows oil and gas corporations, as well as voters in fossil fuel regions, to participate in the carbon-free transition rather than fighting a losing battle against increasingly ambitious emission reductions goals.

However, CCS also has its critics. From an environmental point of view, CCS is currently not a real solution for emission-free electricity, as current approaches typically capture 85 to 95 percent of the CO2 from power plants. And since systems equipped with CCS usually require 15 to 25 percent more fuel to generate a certain amount of electricity due to the additional energy consumption of the CCS process itself, they can also lead to increased emissions of harmful local pollutants such as NOx and fine dust in the absence of additional ones Controls that further undermine their environmental impact. Finally, given the historical responsibility of these companies to hamper climate policy in the past, the above political benefits CCS offers by allowing fossil fuel producers to participate (and benefit from) climate change are anathema to many proponents.

So while CCS has the potential to be a critically important and broadly applicable climate solution adopted by both sides of the political spectrum, it risks becoming an “orphaned” solution abandoned by climate activists who refuse to use fossil fuels oppose, as well as climate deniers who reject any kind of CO2 reduction policy. Indeed, a deluge of misinformation in recent years has exacerbated these challenges in the public eye, from those looking to obscure the reality of climate change to those who raise unfounded fears about the risks posed by this technology, for example before catastrophic leaks from saving facilities on the other hand. To see the promise and limitations of CCS more clearly, you need to first look at the state of the art and its track record to date.

Previous CCUS deployments

Carbon capture technology was first used in the 1930s to remove CO2 from salable natural gas reservoirs, although this CO2 was not stored at the time but was used for applications ranging from industrial solvents to beverage carbonation. Storage of CO2 deep underground dates back to the 1970s when CO2 captured from natural gas processing facilities was injected back into oil fields in Texas to boost production in a process called Enhanced Oil Recovery (EOR). Only since 1996, when the Sleipner project began to store CO2 in salt formations in the North Sea, has CCS been used as an instrument for climate protection on a commercial scale.

Today, the IEA counts 22 large-scale CCUS systems in operation worldwide with a combined capacity to record more than 40 tonnes (Mt) of CO2 per year, as well as 30 other projects in various planning stages. While this existing project base has demonstrated the viability of CCUS and has proven that geological storage is effective and safe (in some cases there have been no significant leaks or other incidents after decades of operation), it barely scratches the surface of what is required is; the IEA's Sustainable Development Scenario predicts a storage requirement of 5.6 gigatons per year by 2050. The majority of the existing plants are still used in natural gas processing plants, but the variety of applications is steadily increasing to store CO2 from power generation and from the production of fertilizers, ethanol, hydrogen, synfuels and steel.

In the future, CCUS technology is very likely to find its most common and important uses in these industrial applications. As discussed in the first article, carbon capture is essential for the production of low-emission “blue” hydrogen from natural gas, which in turn is likely to be an important contributor to the decarbonization of industries such as steel and cement, and shipping and aviation. Aside from the need to produce hydrogen as an emission-free fuel for industrial heating needs, carbon capture is also needed to offset the CO2 emissions inherent in processes such as cement calcination. Overall, the IEA's latest scenario for sustainable development based on the Paris Agreement is based on the fact that CCUS delivers up to two thirds of the CO2 reductions through heavy industry and half of all aviation fuels are produced by carbon-free synfuels.

Apart from the fact that the use of CCUS for most industrial applications is essential for the decarbonization of these “difficult to reduce” sectors in which there are no alternative paths, the use of CCUS also offers a cost advantage over CCUS in power generation. The lower the concentration of CO2 in a flue gas stream and the lower its pressure, the more difficult and expensive it is to separate it for separation and storage, as prescribed by the laws of thermodynamics. Most industrial applications deliver more concentrated exhaust gas flows at higher pressure than power generation with corresponding cost advantages. According to the Carbon Capture Institute, carbon capture for large-scale natural gas processing, fertilizer production, or ethanol production can be achieved at a cost of $ 20 per tonne or less, while the cost of capturing it in a natural gas power plant is typically $ 100 per tonne or more . The costs for the separation from the higher CO2 flows from coal-fired power plants as well as steel and cement production plants are in between.

According to IEA estimates, this translates into a median tiered cost of $ 91 per megawatt hour (MWh) for combined cycle natural gas (CCUS) and $ 112 per MWh for coal with CCUS – roughly double today's tiered costs for wind power. and solar energy. This should of course become more and more competitive, as the costs for integrating more wind and sun with very high grid penetration increase, as expected in the modeling studies discussed above. And since it is the most established zero (or near-zero) emissions technology, it has the advantage of having a relatively safe cost compared to advanced nuclear or unconventional geothermal plants whose future costs and technology development paths are less certain.

In addition, CCUS in combination with biomass power plants – known as "BECCS", for bioenergy with carbon capture and storage – offers the tempting prospect of negative emissions, since biomass raw materials bind carbon as they grow and the CCUS equipment absorbs the CO2 emissions from their subsequent growth Combustion. While BECCS is not as “captivating” as direct air capture technologies, BECCS has yet to be deployed on a large scale and raises reasonable concerns about the scalability and impact of land use emissions from biomass fuel supplies, the only solution to negative emissions on existing ones commercial technology based. Hence, some of the BECCS is included in most of the most cost-effective modeled pathways to meet the goals of the Paris Agreement, including the IEA sustainable development scenario.

CCUS is a relatively mature technology, but there are still significant ways to reduce costs. In fact, the cost of capturing CO2 from a coal-fired power plant has been reduced by about 50 percent over the past 15 years, according to the Carbon Capture Institute, mainly through learning by doing, economies of scale, and a growing ecosystem of vendors and commercial partners for recovery projects like EOR. Further reductions in the cost of CO2 capture – which make up the bulk of the total cost of the CCUS system – can be accelerated by deploying it in larger facilities and by using the modular and standardized design of the capture equipment, which enables the equipment to be mass-produced, and its construction (thereby reducing the cost of capital and the time to reach revenue).

Although CO2 capture is the main cost driver of CCUS, its cost-effectiveness is also influenced by the costs of CO2 transport and storage. In the transportation sector, economies of scale through pipelines are driven by utilization levels, which can be increased through the development of CCUS hubs around a variety of sources, such as: B. a natural gas processing plant near a gas-fired power plant and a steel mill. The storage costs depend largely on the type of injection site in question; Sites with well-characterized geology and access to existing infrastructure – mainly oil and gas wells – are more cost-effective than previously unexplored greenfield sites. Onshore locations also generally offer much lower cost storage than offshore locations, although they can face obstacles from existing or nearby land uses and / or public opposition to fossil fuel-related infrastructures.

Next generation separator technologies promise further cost reductions and better emissions performance. A wide range of reaction pathways are followed, including improvements to core components such as solvents, sorbents, and membranes; Advances in pre-incineration approaches that first remove CO2 from raw materials in a synthesis gas conversion process that provides higher concentrations of CO2 than post-incineration capture; Oxygen incinerators that burn fossil fuels in almost pure oxygen instead of air and provide a concentrated stream of CO2 for highly efficient capture and elimination of NOx emissions; and a variety of other techniques. While some of these technologies can be used as retrofits, more advanced approaches such as oxy-fuel combustion require radically different plant designs and must be developed in the greenfield. The US Department of Energy's Office of Fossil Energy has set R&D targets for demonstrating second generation technologies that can reduce CCUS electricity costs by 20 percent by 2025, with the goal of commercial adoption by 2030, and for " transformational "technologies that offer a 30 percent cost reduction for demonstration purposes in 2030 and deployment by 2035.

Finally, in some cases, the economics of CCUS can potentially be significantly improved in applications where captured CO2 can be sold to end users. In fact, most of the CCUS projects in the US so far have been developed for EOR thanks to the proceeds from the sale of CO2. While EOR is clearly not a desirable end-use market from a climate change perspective, more and more other uses for CO2 are being explored, including in concrete which uses CO2 instead of water when cured (which has the added benefit). to strengthen the material), synfuels made with clean hydrogen for aviation, various chemicals such as methanol and polymers, algae and bioproducts made from algae, as well as carbon fibers.

It is estimated that carbon usage could become a $ 1 trillion market by 2030, which is a critical source of market pull and additional revenue to grow the industry if there is not a high enough price for carbon or regulatory requirements for the industry CO2 capture are available. However, while products like concrete and plastics offer much longer-term – or even essentially permanent – sequestration, other uses such as synfuels release sequestered CO2 during combustion like other climate-neutral biofuels. The markets for uses that lead to permanent storage are also very limited compared to the scope of the challenge; A study by Nature Climate Change states that less than 5 percent of the CO2 capture required to achieve the goals of the Paris Agreement can be permanently sequestered through use, which also underscores the need for large-scale geological storage.

Regardless of the scope of its ultimate role as a source of solid, zero-emission power generation worldwide, CCUS is an essential technology for the decarbonization of industrial end-use applications. In developing countries with relatively young fleets of fossil fuel-fired power plants, CCUS could be the main carbon-free technology as it needs to be prevented from being stranded decades before the end of their useful life. As a result, virtually any country seeking long-term emissions reductions should consider taking policy steps to expand capture facilities and the transportation and storage infrastructure to support them.

Research, development and demonstration

Solid R&D funding for CCUS can help lower the cost of both established and emerging capture technologies and demonstrate the feasibility of new pathways. The most important funding areas include front-end engineering design studies (FEED), an increased focus in research and development on the recording of emissions from industry and natural gas-fired generation (instead of the traditional focus on coal) as well as pilot and demonstration projects for next-generation technologies — especially those that require the construction of integrated greenfield facilities, such as B. Oxy Fuel Combustion Approaches. Funding can also support the development and commercialization of products that use trapped carbon, such as: B. cement or organic products based on algae.

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Reduction of upfront costs

Similar to other early-stage clean energy technologies, CCUS is capital intensive and measures that reduce upfront costs play a key role in accelerating deployment. These can also reduce the cost of CCUS devices by creating incentives for use in larger facilities and by supporting the development of modular, standardized system components. Appropriate policy mechanisms may include soft loans, loan guarantees, accelerated depreciation, and tax-exempt bonds for private activities to lower interest rates and the cost of capital. Investment grants and tax credits can be used to reduce the overall cost of projects.

Since the cost of CO2 capture increases with lower CO2 concentrations in the flue gases, funding for capital costs should to some extent be tailored to different applications, contexts and political goals. For example, natural gas and bioenergy power plant retrofits may be more subsidized than coal in markets where coal-fired power plants are reaching the end of their useful life and are not competitive in the market (e.g. the United States) or in regions with short-term goals for the complete phase-out of coal. For greenfield integrated CCUS plant concepts, even higher levels of support are likely to be warranted if they are required for transformative approaches.

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Operational support

Measures to improve the economic viability of plants and increase the security of income can also help secure project financing and lower capital costs, and have the advantage that they pay for the fulfillment of the specific goal of reducing CO2 emissions. Appropriate types of support vary by country and jurisdiction, but may include tax credits, guaranteed payments such as feed-in tariffs and / or contracts for difference, and may be based on kilowatt-hours of CCUS-equipped power generation or tons of carbon captured and used or stored.

As with capital support measures, operational support should take into account different applications and policy objectives. For example, incentives that reward stored amounts of CO2 (such as the 45Q tax credit in the US) will provide greater incentives for CCUS to be used in coal than in natural gas, while natural gas may be favored through incentives for electricity in markets like the US where gas is more competitive than coal. Eligibility for these incentives can also be tailored to prioritize sectors with the greatest long-term impact on emissions reduction, such as industrial applications and BECCS.

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Public procurement of CCU products

The economics of business in carbon capture can also be improved by developing markets for products that use captured carbon. Government commitments to give priority to these products can prove their viability and in many cases represent a significant source of demand, such as: B. carbon-binding cement for public construction projects or synfuels, which are made from hydrogen and captured CO2 for military fuel needs. As a first step towards procurement commitments, agencies can partner with manufacturers of CO2-utilizing products to investigate, test and demonstrate their feasibility.

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Support for infrastructure hubs

The economics of the infrastructure for transporting and storing CO2 can be improved by increasing its usage rates by installing CCUS devices at different sources in a given area. Industrial plants and power plants are often built in close proximity due to the sharing of fossil fuels, and they may also be located near suitable reservoirs of depleted oil and gas wells.

Grants or other types of financial support for the planning and construction of infrastructures for shared use at designated hubs can improve their profitability as well as the profitability of the associated CCUS use and help these projects secure financing. The use of CCUS at multiple facilities in an area can also serve economic development and political goals by attracting new investments in industrial and / or fossil fuel producing regions and demonstrating the potential of this technology to enable them to participate in the transition to enable clean energy.

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In the Black Pump power station of the European electricity company Vattenfall near Berlin, employees will be working on September 7, 2008 on pipes that carry liquid CO2.MICHAEL URBAN / DDP / AFP ABOUT GETTY IMAGES

Advanced Nuclear: A Safer, More Scalable Nuclear Renaissance?

Nuclear reactors now make up 18 percent of the world's zero-emission electricity and, according to the IEA, have avoided 55 gigatons (Gt) of CO2 emissions over the past 50 years, making them one of the largest and longest-standing solutions to climate change. But despite the increasing urgency of the climate challenge, the global nuclear fleet is shrinking. In 2019, 5.5 gigawatts (GW) of new nuclear capacity were brought on line and 9.4 GW decommissioned, with 13 reactors in Japan, the US, Switzerland, Germany, South Korea, Russia, Sweden and Taiwan permanently shut down – only six of them were at least 40 years old and at the end of their useful life. Of the 60.5 GW nuclear power plants under construction, more than half are concentrated in China, Russia, South Korea, India and the United Arab Emirates.

There are several reasons for this downward trend in conventional nuclear power in most global markets. Meltdown at Fukushima Daiichi reactor in Japan following an earthquake and tsunami in 2011 has raised the safety concerns surrounding this technology after the 1957 incidents at Sellafield and 1979 on Three Mile Island, despite the fact that the health and safety effects of the Incidents were ultimately minimal. Japan responded by temporarily shutting down all of its nuclear power plants, few of which have been brought back on line, and Germany, Belgium, Spain and Switzerland pledged to begin phasing out nuclear power entirely.

Even in countries with competitive electricity markets, more and more nuclear power plants are being shut down for economic reasons, as they have to contend with cheaper – and often subsidized – wind and solar energy and, in some cases, with cheaper natural gas cases (e.g. the USA) . Finally, contrary to the ever-decreasing cost of renewable energy, construction costs for new nuclear power plants are rising, with recent projects in the US, France, UK and Finland suffering from sharp cost increases and delays that have resulted in some projects being abandoned.

In most cases, the emission-free electricity from these power plants is replaced by coal or natural gas electricity, which undermines the climate targets. In Germany, eleven of the country's 17 nuclear power plants have been shut down in the past ten years, leading to a 5 percent increase in CO2 emissions and an estimated 1,100 deaths per year from additional harmful local pollutants. As discussed earlier in this report, the loss of solid zero-emission resources increases the cost of meeting future emission reduction targets. Um diesem Trend entgegenzuwirken, besteht ein wachsendes Interesse an radikal anderen Ansätzen für die Gestaltung und den Einsatz der Kernenergieerzeugung, die darauf abzielen, den heutigen politischen und wirtschaftlichen Gegenwinden zu begegnen und die Branche auf einen Wachstumskurs zurückzuführen.

Fortschrittliche Nukleartechnologie-Pfade

Fortschrittliche Kernreaktortechnologien unterscheiden sich im Design, aber sie alle adressieren die Herausforderungen, denen sich herkömmliche Kernkraftwerke gegenübersehen, auf unterschiedliche Weise. Sie werden hauptsächlich aus vorgefertigten Komponenten zusammengebaut, und viele können in modularen Schritten von Megawatt (MW) oder weniger eingesetzt werden, was im Vergleich zu den standortspezifischen Design- und Bauprozessen, die für den traditionellen Gigawatt-Maßstab erforderlich sind, das Potenzial bietet, die Kapitalkosten zu senken und die Bereitstellung zu beschleunigen Anlagen. Im Gegensatz zu aktuellen Kraftwerken, die für einen effizienten Betrieb mehr oder weniger konstant laufen müssen, ermöglichen die meisten fortschrittlichen Nuklearkonzepte es den Kraftwerken, die Erzeugung schneller hoch- und herunterzufahren, was sie zu angemessen flexiblen Energiequellen macht, um die wahrscheinlich variablen Wind- und Solargeneratoren zu unterstützen den Großteil des Stroms in einem dekarbonisierten Netz bereitzustellen. Alle verfügen über eine Vielzahl passiver oder inhärenter Sicherheitsfunktionen, die es vermeiden, sich im Falle einer Fehlfunktion auf aktive Steuerungen, Betriebseingriffe oder Ersatzstromversorgung zu verlassen, den Betrieb zu vereinfachen und möglicherweise öffentliche Bedenken zu mildern, die trotz der beispielhaften Sicherheitsaufzeichnungen bestehender Anlagen bestehen bleiben.

Einige fortschrittliche Kernreaktorkonzepte könnten auch im Vergleich zu bestehenden Anlagen einzigartige Vorteile bieten. Reaktoren, die bei höheren Temperaturen als herkömmliche Reaktoren betrieben werden, können geeignet sein, industrielle Prozesswärme für Anwendungen wie die Wasserstoff- oder Ammoniakproduktion bereitzustellen, was einen zusätzlichen Einnahmestrom zur Verbesserung der Anlagenökonomie bietet. In ähnlicher Weise wurden für wasserarme Länder wie Saudi-Arabien Hybridkonstruktionen vorgeschlagen, die fortschrittliche Kernkraftwerke mit Entsalzungsanlagen kombinieren, die die betriebliche und wirtschaftliche Effizienz maximieren würden, indem sie bei Bedarf Strom ins Netz und in eine Entsalzungsanlage zur Erzeugung von frischem Strom einspeisen Wasser zu anderen Zeiten. Da die meisten dieser fortschrittlichen Reaktoren in viel kleineren Größen als herkömmliche Anlagen eingesetzt werden können, haben sie das Potenzial, von kleineren Versorgungsunternehmen, an abgelegenen oder netzfernen Standorten oder in kritischen Einrichtungen wie Militärstützpunkten eingesetzt zu werden.

Laut einer aktuellen MIT-Studie gibt es drei Haupttypen fortschrittlicher Reaktoren, die ausreichend ausgereift sind, um bis 2030 ein realistisches Potenzial für eine Kommerzialisierung zu haben: kleine modulare Reaktoren auf der Grundlage von Leichtwasserreaktoren der Generation III (LWR) und Natriumschnellreaktoren und modulare Hoch modular -temperaturgasgekühlte Reaktoren der Generation IV-Familie. Diese Typen können nach der Art des Kühlmittels kategorisiert werden, das verwendet wird, um die Wärme vom Reaktor zu den Erzeugungseinheiten zu übertragen, was eine Vielzahl von Konstruktionsmerkmalen der Anlage sowie das Neutronenspektrum des verwendeten Brennstoffs bestimmt, das durch das Vorhandensein oder Fehlen verschiedener Arten von Moderatoren, die Neutronen verlangsamen, um Spaltreaktionen zu erzeugen.

Kleine modulare Leichtwasserreaktoren (SMRs) verwenden Wasser als Kühlmittel und arbeiten im thermischen Neutronenspektrum, wobei konventioneller Uranbrennstoff und Wasser als Moderator verwendet werden. Diese SMRs nutzen jahrzehntelange Betriebserfahrung mit der groß angelegten Reaktortechnologie der Generation III, auf der sie basieren, verwenden jedoch kleinere und einfachere Konfigurationen mit passiven Sicherheitsfunktionen, die wenig oder keine Notstromversorgung benötigen und im Falle eines Ausfalls eine langfristige Kernkühlung bieten Unfall. SMR-Konstruktionen haben sich im Feld für Marineanwendungen bewährt, und 2019 wurde das schwimmende 70-MW-Akademik-Lomonosov-Kernkraftwerk in Russland an das Stromnetz angeschlossen und anschließend als erstes SMR-Kraftwerk weltweit in Betrieb genommen.

Nach Angaben der Internationalen Atomenergiebehörde (IAEA) gibt es 25 landgestützte SMR-Designs auf Basis der LWR-Technologie in verschiedenen Entwicklungsstadien in 12 Ländern, darunter die USA, Großbritannien, Kanada, Frankreich, Russland, China, Japan und Südkorea. 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.

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.

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.

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.

Qiabuqia, China

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

Saxony, Germany

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

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

Vendenheim, France

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

Cornwall, United Kingdom

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

Cornwall, United Kingdom

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

Otaniemi, Finland

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

Utah, United States

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

California, United States

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

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.

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.

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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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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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