S. WATTANASOPONVANIJ, Independent Consultant, Rayong, Thailand
Small modular reactors (SMRs) are nuclear fission reactors that generate up to 300 megawatts electric (MWe) per unit, emphasizing modularization, factory fabrication and enhanced safety features. The SMR concept aims to address challenges faced by traditional large nuclear plants, including high costs and long construction times.
Most SMRs currently proposed use light-water technology, benefiting from the experience of existing pressurized and boiling water reactors. While several designs have advanced to licensing and construction stages, commercial deployment remains limited, with only a few first-of-a-kind SMR projects expected to begin by the mid-2020s, often relying on government funding or support from state utilities (TABLE 1).
The regulatory landscape is slowly evolving, yet still reflects frameworks for larger reactors. Key challenges include licensing processes, supply chain qualifications and fuel availability for non-light-water designs. Thus, widespread commercial rollout is unlikely before the 2030s, with significant cost reductions expected only during the Nth-of-a-kind stage, potentially allowing for a large-scale rollout by the 2040s, contingent on policy stability and success with early projects.
SMRs are viewed as versatile energy systems not only for electricity generation but also for providing low-carbon heat, hydrogen (H2) and process energy to various industries. They provide reliable, low-carbon power 24/7, complementing intermittent renewable sources like wind and solar. Unlike large nuclear plants, SMRs can be built incrementally, reducing project risks and aligning with local energy needs. While large nuclear plants also face high initial costs [with recent projects in Europe and the U.S. exceeding $100 per megawatt-hour (MWh)], they benefit from lower costs per unit when built in larger quantities. SMRs aim to achieve competitive pricing through modular construction and shorter build times, but these benefits must still be validated at a commercial level.
Power generation: SMRs vs. solar, wind, fossil + carbon capture and storage (CCS) and large nuclear. The economics of SMRs compared to other energy sources (e.g., wind, solar) is a complex and debated matter (FIG. 1). Currently, wind and solar energy are significantly cheaper per kilowatt-hour (kWh) than projected SMR costs. For instance, the NuScale-UAMPS project in the U.S. experienced a price increase from $55/MWh to $89/MWh, leading to project cancellation in 2023 due to customer withdrawals. While large nuclear plants also incur high upfront costs, they can benefit from economies of scale if constructed in series. SMRs aim to reduce costs through modular factory construction and quicker build times, but these advantages are yet to be verified on a commercial scale.
SMRs offer reliable, low-carbon energy consistently, serving as a valuable complement to intermittent renewable sources. Their placement at former coal sites or near industrial hubs allows for the use of existing infrastructure and regional expertise. The U.S. is exploring SMRs as a means to modernize aging fossil fuel and nuclear facilities while reducing carbon emissions.
However, it is essential to recognize that while the levelized cost of electricity (LCOE) for renewables appears lower, this figure often excludes the necessary storage or backup systems for a reliable supply. When factoring in these costs, the gap narrows. SMRs provide energy security and eliminates fuel price volatility and carbon dioxide (CO2) emissions over their operational lifespan, which can deliver significant long-term value.The trade-off lies in the high capital and financing costs of nuclear energy—developers require low financing costs and stable regulatory environments to remain competitive.
In summary, while SMRs currently have higher energy costs than wind or solar, they may become viable competitors in delivering reliable clean energy as costs decrease and system-level factors are considered. Decision-makers must balance the lower but intermittent energy from renewables with the higher but reliable output from nuclear power, also considering the costs of carbon emissions, fuel and storage.
Industrial process heat: SMRs for steel, cement and chemicals vs. H2 and electrification. Decarbonizing industrial heat in sectors like steel, cement, petrochemicals and refining is challenging due to the high temperatures needed [400°C–1,000°C (752°F–1,832°F)], which are currently met by burning fossil fuels (FIG. 2).1 Electrifying these processes with existing technologies is difficult. While SMRs typically produce steam at about 300°C (572°F), advanced high-temperature reactors [like high-temperature gas-cooled reactors (HTGRs) and molten salt reactors] can generate heat at 600°C–800°C (1,112°F–1,472°F), providing a viable alternative to fossil fuels.
Japan's high-temperature engineering test reactor (HTTR)2 has successfully achieved heat production at 950°C (1,742°F) for 50 days (d), paving the way for direct thermochemical H2 production. However, integrating a nuclear reactor into industrial settings presents challenges related to co-location, safety and regulatory approvals, meaning initial deployments will likely be limited to pilot projects.
Industries are exploring three main decarbonization strategies: electrification using renewable energy, H2 combustion and nuclear heat from SMRs, or waste heat from nuclear plants (TABLE 2). A hybrid approach may develop, utilizing electric heating or H2 for some processes while relying on nuclear heat for others.
The economic feasibility of SMRs is influenced by energy prices and carbon costs. If natural gas remains cheap and carbon costs low, transitioning to nuclear power may not be cost-effective. However, as carbon prices rise and renewable energy becomes scarce, nuclear options could become more appealing due to their consistent heat supply. SMR developers also point to cogeneration, providing both electricity and heat, as a way to enhance asset utilization and profitability.
While there is excitement about SMRs quickly decarbonizing industries, the reality involves phased pilot projects and learning curves. Reliability is crucial; any disruption in heat supply can halt production. Therefore, nuclear solutions must be dependable. Many companies are also pursuing electrification and H2 initiatives to reduce emissions, positioning SMRs as a medium- to long-term strategy to eliminate combustion emissions in industry.
In summary, companies are assessing three key decarbonization pathways: electrification with renewables, H2 combustion and nuclear heat solutions. The economic viability of SMRs will depend on evolving energy markets, but they offer the promise of efficient heat supply in the future.
H2 production: SMRs for clean H2 vs. green [produced using renewable electricity (solar, wind)] and blue H2 [produced from natural gas (methane) using steam reforming)]. SMRs (reactors) can enable “pink” H2 (nuclear-derived H2) either by providing electricity for electrolysis or by supplying high-temperature heat for more efficient H2 production processes. The U.S. Department of Energy (DOE) estimates a single large 1,000-MWe reactor could produce ~150,000 tpy of H2 (300 Mwe could produce 45,000 tpy of H2). H2 could feed multiple uses as ammonia for fertilizer, refinery feedstock, steel mills (for iron reduction), synthetic fuels, etc. For example, the Nine Mile Point nuclear station in New York (U.S.) started a 1.25-MW demonstration scale plant that produced 560 kg of H2 per day in 2023 using its electricity in an electrolyzer, the first nuclear-powered H2 in the U.S.
For the high-temperature route, SMRs for H2 lies in electrolysis and thermochemical processes but require heat input. High-temperature steam electrolysis (HTSE) uses steam [around 700°C–850°C (1,292°F–1,562°F)] in solid oxide electrolyzer cells to produce H2 with lower electricity consumption per kg of H2. At the Palo Verde nuclear station in Arizona (U.S.) (~4 GWe), the DOE is supporting a low-temperature electrolysis demonstration to produce H2 for power-to-power and other potential uses.3 Separately, high-temperature solid-oxide co-electrolysis can produce syngas (H₂ + CO) suitable for downstream Fischer–Tropsch eFuels. TABLE 3 is an example of a consolidated list of nuclear-to-H2 projects worldwide.
For cost comparison, nuclear-derived H2 (pink) will struggle to compete on price unless nuclear power is inexpensive or heavily utilized. If an SMR produces only H2, the cost of H2 reflects the LCOE of the reactor and efficiency losses. By contrast, green H2 often has lower capacity factors unless paired with very large renewable overbuild or storage, and there is also a seasonal aspect. Thus, the competition between pink and green H2 will depend on the energy mix. Regions with abundant cheap renewables may favor green H2, while those prioritizing always-available production might consider nuclear H2 (TABLE 4).
Nuclear H2’s market potential is uncertain, with large facilities unlikely to begin operating until the late 2020s. Most SMRs are presently focused on electricity rather than H2. If successful, we may see nuclear hubs producing H2 and related products in the future. For immediate investment, green and blue H2 projects are more viable. While nuclear can supply significant clean H2 reliably, it requires a long-term commitment. Companies in need of H2, like refineries, should track SMR developments and might consider pilot partnerships to manage future carbon risks, but will likely prioritize green H2 in the short term.
District heating (DH) and cogeneration: SMRs vs. geothermal, biomass, heat pumps. DH systems provide hot water and sometimes steam for heating and hot water needs, particularly in colder climates. Using nuclear energy for DH and other non-electric applications is not a new concept. According to an International Atomic Energy Agency (IAEA) report, there are 79 reactors globally delivering non-electric heat and other uses, primarily in Russia and Ukraine.1
Recent developments have highlighted how nuclear energy can be effectively employed at a city scale. For example, in China, the Haiyang nuclear district heating project utilizes a ~23-km pipeline to deliver approximately 4.6 MM gigajoules (GJ) of heat, significantly reducing coal use by about 410,000 t and CO2 emissions by around 760,000 t.9
Heat pumps are valuable tools for decarbonizing DH systems, but their effectiveness is limited by two factors: (1) the availability of low-temperature heat sources, such as seawater or industrial waste heat; and (2) the higher supply temperature requirements of older DH networks, which can reduce the efficiency of heat pumps and necessitate system upgrades. A study on SMR applications in Finland did not consider heat pumps due to the lack of a sufficient local heat source.10
In Helsinki, one analysis indicated that SMR heat could be competitive in terms of LCOH compared to alternatives. However, it emphasized that nuclear energy’s financial viability depends heavily on factors like financing conditions and long-term demand certainty.11 Estimates for SMR heat costs in Finland suggest an LCOH of approximately 15 €/MWh–30 €/MWh, with additional operational and fuel costs of around 5 €/MWh–10 €/MWh.12 The analysis also highlighted why cities and investors might opt for smaller, short-term projects, even if they result in higher operating costs, due to the longer lifespan (60 yrs)13 of SMRs compared to boilers and heat pumps (20 yrs–25 yrs).
Part 2 of this article will appear in the February issue. HP
LITERATURE CITED
World Nuclear Association, “Nuclear process heat for industry,” May 2024, online: https://world-nuclear.org/information-library/non-power-nuclear-applications/industry/nuclear-process-heat-for-industry
Fujimoto, N., N. Nojiri, Y. Tachibana and T. Mizushima, “Operation of the high-temperature engineering test reactor,” Japan Atomic Energy Agency (JAEA), Department of HTTR, online: Microsoft PowerPoint - HTTR WS 1 Fujimoto.ppt
Patel, S., “Power-to-power hydrogen demonstration involving largest U.S. nuclear plant gets federal funding,” Power, October 14, 2021, online, https://www.powermag.com/power-to-power-hydrogen-demonstration-involving-largest-u-s-nuclear-plant-gets-federal-funding
International Energy Agency (IEA), “The future of hydrogen: Seizing today’s opportunities,” 2019, online: https://www.iea.org/reports/the-future-of-hydrogen
Oni, A. O., K. Anaya, T. Giwa, G. Di Lullo and A. Kumar, “Comparative assessment of blue hydrogen from steam methane reforming, autothermal reforming, and natural gas decomposition technologies for natural gas-producing regions,” Energy Conversion and Management, Vol. 254, February 2022.
World Nuclear Association, “Hydrogen production and uses,” May 2024, online, https://world-nuclear.org/information-library/energy-and-the-environment/hydrogen-production-and-uses
Wendt, D. S., L. T. Knighton and R. D. Boardman, “High-temperature steam electrolysis process performance and cost estimates,” Idaho National Laboratory, March 2022, online: https://inldigitallibrary.inl.gov/sites/sti/sti/Sort_60759.pdf
U.S. Department of energy (DOE) Energy earthshots, “Hydrogen shot: An introduction,” online: https://www.energy.gov/sites/default/files/2021-06/factsheet-hydrogen-shot-introduction.pdf
World Nuclear News, “China's first commercial nuclear district heating scheme expands,” November 2024, online: https://www.world-nuclear-news.org/articles/chinas-first-commercial-nuclear-district-heating-scheme-expands
Teräsvirta, A., S. Syri and P. Hiltunen, “Small nuclear reactor—Nordic district heating case study,” Energies, July 2020, online: https://www.mdpi.com/1996-1073/13/15/3782
Värri, K. and S. Syri, “The possible role of modular nuclear reactors in district heating,” Energies, June 2019, online: https://www.mdpi.com/1996-1073/12/11/2195
Partanen, R., “Nuclear district heating in Finland: The demand, supply and emissions reduction potential of heating Finland with small nuclear reactors,” Think Atom, 2019, online: https://thinkatom.net/wp-content/uploads/2019/04/nuclear-district-heating-in-finland_1-2_web.pdf
The International Atomic Energy Agency (IAEA), “Management of life cycle and ageing at nuclear power plants: Improved I&C maintenance,” August 2004, online: https://www-pub.iaea.org/MTCD/Publications/PDF/te_1402_web.pdf
Smith Wattanasoponvanij is an independent consultant with more than 10 yrs of experience in technology development and process engineering across the petrochemical and energy-transition landscape. His work spans business and market studies, technology research, process R&D and design, and feasibility studies, with practical experience in scaling technologies from laboratory to pilot and commercial deployment. He also supports organizations through fast-cycle technology development, cross-functional R&D-to-business alignment, and structured R&D methods to accelerate time-to-market.