On February 9, 2026, Tokyo Electric Power Company Holdings (TEPCO) confirmed the restart of the 1,356-megawatt Unit 6 at Kashiwazaki-Kariwa in Niigata Prefecture, with full commercial operations expected by mid-March. The reactor — offline since the 2011 Fukushima Daiichi accident for safety enhancements and regulatory review — will be the first TEPCO unit to resume service in nearly 14 years and is projected to generate about 9.5 terawatt-hours (TWh) annually once fully ramped up.

Japan now has 15 operating nuclear reactors with a combined capacity of about 33 gigawatts (GW), out of an operable fleet of 32. In 2024, this fleet produced roughly 83 TWh — about 9 per cent of total electricity generation — as nuclear capacity gradually returned after extensive safety reviews and public debate over nuclear energy’s role.

Impact on fossil fuel use and LNG imports

Analysts and government estimates suggest the added nuclear output from Unit 6 could displace about 1.3 million tonnes of LNG — equivalent to roughly 62 billion cubic feet of natural gas imports annually — if generation from nuclear substitutes for gas-fired power. That displacement figure reflects Japan’s ongoing effort to reduce reliance on imported fossil fuels for electricity, a legacy effect of all reactors shutting down following the 2011 tsunami and nuclear accident.

Natural gas previously accounted for about 33 per cent of Japan’s electricity mix in 2024, with LNG imports serving as a critical feedstock for gas-fired plants. Japan remains the second-largest LNG importer globally after China, though annual LNG demand has declined in recent years as nuclear and renewables have grown. Japanese companies imported roughly 9 billion cubic feet per day (Bcf/d) of LNG in 2025, down from about 11 Bcf/d in 2018, according to market data. Australia, Malaysia, Russia and the United States have been among Japan’s top LNG suppliers, with Australian volumes rising in recent years while U.S. shipments declined.

The increase in nuclear output also fits within Japan’s long-term energy strategy, which aims to raise nuclear’s share of electricity generation to around 20 per cent by 2040. Meeting that goal would require up to 30 reactors in operation, meaning some of the 17 currently non-operating reactors would need to clear regulatory and local hurdles before restarting. Three units have initial Nuclear Regulation Authority approval and six more are under review.

Renewables and policy context

Alongside nuclear, Japan’s power mix has seen renewable generation grow steadily. Solar capacity, in particular, expanded rapidly in the past decade, and preliminary statistics indicate that renewables accounted for more than 26 per cent of electricity generation in 2024, with solar alone contributing more than 11 per cent and hydro nearly 8 per cent. Fossil fuels, including coal and natural gas, still made up the majority of generation but have trended downward from levels exceeding 70 per cent earlier in the decade.

Japan’s evolving energy policies — including its 6th Strategic Energy Plan and the broader Green Transformation (GX) agenda — reinforce these shifts. The plans aim to nearly double renewable generation’s share and boost nuclear’s role by 2030 while reducing fossil fuel dependence significantly. Officials see nuclear as an essential part of ensuring energy security and reducing electricity price volatility, particularly in a country that imports roughly 90 per cent of its energy needs.

Historical and public sentiment backdrop

Japan’s reliance on nuclear power draws directly from its pre-2011 energy configuration, when reactors provided around 30 per cent of electricity. Following the Fukushima disaster, all reactors were taken offline for safety upgrades under new regulatory standards, and public opinion tilted sharply away from nuclear generation. That shift significantly increased fossil fuel use and raised energy import costs.

Efforts to restart large reactors like Kashiwazaki-Kariwa have often been met with local debate and scrutiny over safety and disaster preparedness. Approval from regional authorities has been essential for restarts, reflecting lingering public sensitivity to nuclear risks. Still, government policy revisions now emphasize maximizing both renewable and nuclear “carbon-free” power sources, signalling a broader acceptance of nuclear as part of Japan’s decarbonization trajectory.

Market and geopolitical implications

Bloomberg and Reuters reporting over recent years has underscored that Japan’s nuclear comeback is closely tied to broader energy security concerns, including volatile LNG markets and price spikes following global supply disruptions. Analysts have noted that a robust nuclear fleet could insulate Japan from some of these risks, particularly as competition for LNG supplies intensifies in Asia.

NPR highlighted the challenge Japan faces balancing safety, public sentiment and decarbonization goals, noting that nuclear restarts require meticulous regulatory oversight and clear communication to gain social license.

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By Mark Morey

In 2021, for the second consecutive year, US nuclear electricity generation declined. Output from US nuclear power plants totalled 778 million megawatthours in 2021, or 1.5 per cent less than the previous year. Nuclear’s share of US electricity generation across all sectors in 2021 was similar to its average share in the previous decade: 19 per cent.

Six nuclear generating units with a total capacity of 4,736 megawatts (MW) have retired since the end of 2017. Three more reactors with a combined 3,009 MW of capacity are scheduled to retire in the coming years: Michigan’s Palisades is scheduled to retire later this year, and California’s Diablo Canyon is slated to retire one generating unit in 2024 and one in 2025. We compile announced retirement dates and new plants’ intended online dates in our Preliminary Monthly Electric Generator Inventory.

The loss of electricity generation from the retirement of Indian Point Unit 3 in 2021 was partially offset by an increase in the generation of the remaining nuclear fleet at a higher capacity factor. Capacity factors measure how much of the time units operate, and nuclear units tend to be run more of the time than almost all other electricity-generating technologies. The US nuclear power fleet has achieved an average annual capacity factor of at least 90 per cent in every year since 2012. The nuclear capacity factor averaged 93 per cent in 2021.

Although output has been rising from renewable energy sources and from turbine plants using natural gas, the US nuclear fleet continues to operate at high and consistent utilization rates. Financial pressures from competitive wholesale power markets remain the primary cause of nuclear power plant retirements. Four units at two sites in Illinois had announced their intention to retire but then reversed that decision after the Illinois state legislature provided financial incentives to support the nuclear units’ continued operation.

The Bipartisan Infrastructure Law, which was enacted in November 2021, includes the allocation of $6 billion to prevent the premature retirement of existing nuclear power plants. The funding will be made available to nuclear power plants that might otherwise retire and that are certified by the Nuclear Regulatory Commission as safe to continue operations.

Two nuclear generating units now under construction in Georgia (Vogtle Units 3 and 4) plan to come online by the end of 2023. Each unit is rated at 1,114 MW, and they will be the first nuclear units to come online in the United States since Tennessee’s Watts Bar Unit 2 came online in mid-2016.

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This article was published by the US Energy Information Administration on Feb. 7, 2020.

Despite projected growth in natural gas and renewable energy use to generate electricity through 2050, in the Annual Energy Outlook 2020 (AEO2020) Reference case, the U.S. Energy Information Administration (EIA) projects that coal and nuclear power plants will collectively provide more than 25 per cent of US power generation through 2050.

Other scenarios with different assumptions for oil and natural gas supply—which in turn affect natural gas prices—have implications for long-term coal-fired and nuclear-powered electricity generation in the United States.

In the AEO2020 Reference case, the share of electricity generated from coal decreases from 24 per cent in 2019 to 13 per cent in 2050, and the share of electricity generated from nuclear power is projected to fall from 20 per cent in 2019 to 12 per cent in 2050.

In the High Oil and Gas Supply case, increased supply of natural gas results in lower natural gas prices. In this scenario, natural gas-fired electricity generation continues to increase, largely at the expense of coal and nuclear, which fall to 9 per cent and 7 per cent of total electricity generation in 2050, respectively.

Similarly, in the Low Oil and Gas supply case, higher natural gas prices result in coal’s share falling to 16 per cent and nuclear’s share falling to 14 per cent in 2050.

Recent trends for electricity generated from coal and nuclear are the result of historically low natural gas prices, limited growth in electricity demand, state-level clean energy initiatives, and increasing competition from renewable energy.

Several coal-fired power plants, totalling 33 gigawatts (GW) of capacity, have already announced their intention to retire, according to EIA’s survey of power plant operators and the companies’ retirement announcements.

The Reference case projects another 69 GW of coal-fired capacity to retire, mostly by 2025. If realized, the amount of coal-fired capacity retired annually from 2023 through 2025 would exceed the 15 GW of coal-fired capacity retired in 2015, which was the largest amount of coal-fired retirements in EIA’s retirements data, which date back to 2002.

After 2025, EIA projects that only the most efficient coal-fired plants will remain operating through 2050 as natural gas prices rise and coal power plants remain competitive.

EIA assumes that less efficient coal-fired plants will retire by 2025 to comply with the Affordable Clean Energy (ACE) rule. This rule, finalized by the U.S. Environmental Protection Agency (EPA) in June 2019 as a replacement for the Clean Power Plan, directs states to develop plans for improving the heat rates (i.e., thermal efficiencies) of their coal-fired power plants to reduce carbon dioxide (CO2) emissions.

In the AEO2020 Reference case, total U.S. nuclear power generating capacity decreases from 98 GW in 2019 to 79 GW in 2050. Similar to EIA’s projections for coal retirements, most of the projected nuclear power retirements occur between 2020 and 2025.

In the Reference case, nearly 24 GW of nuclear capacity retires: 7.5 GW have already been announced, and EIA’s Reference case projects another 16 GW will retire through 2050 in response to competitive market conditions.

Two new nuclear plants totalling 2.2 GW are projected to come online in the next two years (Georgia’s Vogtle Units 3 and 4), and the existing fleet adds another 2.1 GW of capacity through uprates, or improvements to existing plants.

More information on EIA’s Annual Energy Outlook 2020 is available in the full report. Data for all projections are available in published tables (for the Reference case and side cases) and an interactive table viewer.

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Small modular nuclear reactors could offer significant costs savings compared to diesel generation

Mining operations located in remote Canadian locations could soon power their operations with small modular nuclear reactors which would cut their reliance on carbon intensive and costly diesel.

Canadian Nuclear Laboratories, or CNL, recently presented their small modular reactors (SMR) technology to the mining industry at the Prospectors & Developers Association of Canada convention in Toronto.

Industrial mining sites typically rely on diesel generation to provide electricity to their operations.  In a press release, the company said “The modular approach to construction, deployment and decommissioning of small modular reactor technologies enables a clean, emissions free alternative for the mining and resource extraction sector, even in challenging locations.”

As much as 40 per cent of a mine’s energy use is related to heating and ventilation.  CNL says an SMR can provide the electricity needed to power equipment and vehicles, cut ventilation requirements and deliver passive local area heating to the mine operations.

“Increasingly, nuclear technology is being seen as a viable clean energy alternative for industrial applications,” said Dr. Corey McDaniel, Vice-President of Business Development at CNL.

“Heavy industry, such as mining, is energy intensive and requires a reliable source of electricity, but also in many cases, heat and steam. Next-generation nuclear energy offers the versatility to meet these needs, and does so in a low-carbon, environmentally-sustainable way.”

McDaniel participated in a panel at PDAC 2019 alongside other leaders in Canada’s nuclear and mining sectors.  The group discussed challenges and opportunities to SMR use in mining as well as linkages with the Canadian Minerals and Mining Plan.

“It is critical that we draw in as many perspectives as possible to fully explore the potential of SMR technology in enabling a competitive, low-carbon future for the mining sector in Canada,” added McDaniel.

SMRs could offer significant costs savings compared to diesel generation, particularly for remote industrial operations or small communities.

Canadian Nuclear Laboratories recently announced a staged invitation process for vendors interested in siting an SMR unit on a CNL-managed site.

The company says that while deployment of SMRs is several years away, CNL “is building its expertise and capabilities to support the development of these technologies, and has launched initiatives that would further explore the full range of applications.”

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Japan’s LNG imports could fall as much as 10 per cent in 2019

By Slade Johnson, Victoria Zaretskaya

This article was published by the US Energy Information Administration on March 4, 2019.

In 2018, Japan restarted five nuclear reactors that were shut down after the 2011 Fukushima accident. As those reactors return to full operation, the resulting increase in nuclear generation is likely to displace generation from fossil sources, in particular natural gas.

Because Japan imports all of its natural gas in the form of liquefied natural gas (LNG), increased nuclear power production is likely to reduce Japanese imports of LNG in the electric power sector by as much as 10 per cent in 2019.

Japan now has nine operating nuclear units with a total electricity generation capacity of 8.7 gigawatts. Electricity generation produced by natural gas-fired plants in Japan has been declining annually from its peak in 2014 and is likely to decline further in 2019, while generation from nuclear units will likely increase.

In response to the 2011 Fukushima accident, Japan suspended operations at all nuclear reactors for mandatory safety inspections and upgrades, leaving the country with no nuclear generation from September 2013 to August 2015. Existing coal-fired power plants were already operating near full load; therefore, utilities had to import large volumes of LNG to meet electricity demand.

As the five nuclear reactors were gradually restarted in 2018, they began to offset natural gas-fired generation, and as a result, LNG imports decreased as the reactors reached full operation.

In 2019, their first full year of operation, EIA estimates that the restarted nuclear reactors will further displace Japan’s LNG imports by about 5 million metric tons per year (MMmt/y), or 0.7 billion cubic feet per day (Bcf/d) of LNG. This amount is equivalent to 10 per cent of Japan’s power sector natural gas consumption and 6 per cent of Japan’s LNG imports in 2018.

Consumption of crude oil and petroleum products by power plants also increased between 2011 and 2013, with utilities spending about $30 billion each year for additional fossil fuel imports in the three years following the Fukushima accident. Generation from crude oil and petroleum products returned to pre-Fukushima levels by 2014 mainly as a result of relatively high crude oil prices, and it has since declined further.

Japan relies on imported LNG to meet all of its natural gas demand and imports more LNG than any country, averaging 11 Bcf/d in 2016 through 2018. Japan imports LNG from several countries worldwide.

LNG imports from Australia have grown in the past two years to account for more than one-third of the total imports, and they have displaced imports primarily from Malaysia and Qatar. In 2016 through 2018, these three suppliers accounted for 60 per cent of Japan’s LNG imports.

LNG imports from the United States account for a small percentage of total imports, but they increased from 0.16 Bcf/d in 2017 to 0.3 Bcf/d in 2018, according to data from Japan’s Ministry of Finance.

Japan’s LNG importers have signed long-term contracts with U.S. LNG export projects such as Freeport, Cameron, and Cove Point. Most of Japan’s LNG imports are under long-term contract with existing foreign suppliers, and these contracts are set to expire during the next decade.

The outlook for further LNG import displacement is largely dependent on the number of nuclear restarts, assuming trends in other factors, such as electricity demand and energy efficiency, remain constant. The pace of nuclear restarts has been slow, with the average reactor requiring nearly four years to come back online.

Japan’s long-term energy policy calls for the nuclear share of total electricity generation to reach 20 per cent to 22 per cent by 2030, which would require up to 30 reactors to be in operation. Out of the remaining fleet of 35 operable reactors, 9 are currently operating, 6 have received initial approval from Japan’s Nuclear Regulation Authority, 12 are under review, and 8 have yet to file a restart application.

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