A handful of Democratic legislators are opposed to a plan to build a natural gas power plant in Chesterfield, a proposal that Virginia’s largest utility said will ensure electric grid reliability during expected surges in power demands over the next 15 to 25 years.

Seven delegates and two senators representing the greater Richmond area signed a statement Wednesday issued by the office of Sen. Ghazala Hashmi, D-Richmond. The project proposal “runs counter to the measures the Commonwealth has taken recently to lower carbon emissions and to diversify energy production and storage,” it reads.

In 2020, the Democratic-majority General Assembly passed the Virginia Clean Economy Act, a policy that requires the state’s electric grid to decarbonize by 2045 by transitioning to renewable energy sources and retiring fossil fuel generation sources. 

That same year, Virginia passed the Environmental Justice Act, which requires the state to promote “the fair treatment and meaningful involvement of every person, regardless of race, color, national origin, income, faith, or disability” when developing, implementing or enacting environmental laws, regulations and policies.

The legislators’ opposition to the Chesterfield plant cites projections from Dominion’s long-term planning documents that say the utility’s carbon emissions would increase. The utility produced 21.8 million metric tons in 2021 and estimated it would emit 36 to 43.8 million metric tons by 2048. The proposed 1,000 megawatt Chesterfield plant, which would be sited next to the utility’s now-closed coal-fired plant, is included in Dominion’s estimates. 

About 20,000 people live within a three-mile radius of the proposed plant; 36% of them are low-income, and about 48% are people of color, according to information from the U.S. Environmental Protection Agency included in the lawmakers’ statement.

The opposing legislators also question the cost of the project, which was $600 million in a 2019 iteration of the proposal, but hasn’t been disclosed in the current plan. Dominion’s customers would bear those costs.

“With the VCEA stipulation that most polluting plants be shut down by 2045, the construction of a new and costly power plant makes little fiscal sense,” the statement reads. 

Dominion proposed the natural gas plant last summer as part of its non-binding, long-term planning document, called an Integrated Resource Plan, as a way to meet an expected increase in electric grid load growth, largely due to data center development in the state, more electric vehicle use and efforts to boost homes’ energy efficiency. This type of facility is commonly referred to as a “peaker plant,” because of its intended use during periods of peak demand for electricity.

A challenge of relying solely on renewable technologies like wind and solar during the energy transition is that they’re limited to producing electricity on an intermittent basis, when the sun is shining and the wind is blowing. Federal Energy Regulatory Commission member Mark Christie, a former member of the State Corporation Commission that regulates Dominion, echoed that concern in remarks last May.

When it comes to grid reliability,, “the problem generally is not the addition of intermittent resources — primarily wind and solar — but the far too rapid subtraction of dispatchable resources, especially coal and gas.”

About 95% of the energy generation sources in Dominion’s IRP is from carbon-free sources, including 2,600 megawatts from offshore wind, about 800 megawatts a year from solar and long-duration energy storage devices, which can provide power for over 100 hours instead of the traditional four-hour period, and small modular nuclear reactors, though they are largely unproven at the commercial level. The remaining 5% of new generation sources comes from the Chesterfield plant.

“Renewables alone cannot keep our customers’ power on 24/7, especially with power demand nearly doubling over the coming decades,” said Dominion spokesman Jeremy Slayton. “That is why we need an all-of-the-above, balanced approach that advances the clean-energy transition, but without sacrificing on reliability.” 

Still, community members have joined lawmakers in raising concerns about the planned power plant and some are calling for local action against it.

“Given the significant potential for harm to the community, we urge the Chesterfield County Board of Supervisors to deny Dominion Energy’s zoning application to move forward with the gas plant,” said Aliya Farooq, a founding member of the group Friends of Chesterfield County that formed last year to oppose the proposed plant.

The project still needs approvals from the Department of Environmental Quality for its air permit, Chesterfield County for its land use permit and the SCC for its Certificate of Public Convenience and Necessity. If all of these are acquired, construction of the plant would begin in 2026 and it’s slated to become operational by the end of 2028.

Virginia Mercury is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence.

The allocation is provided as a non-federal match for Energy Northwest’s participation in the U.S. Department of Energy’s (DOE) loan programs office application. The utility wants to develop “up to 12 Xe-100 advanced small modular reactors” capable of generating up to 960 MW of electricity adjacent to the large nuclear-powered Columbia Generating Station in Richland.

The capital allocation received bipartisan support but still needs to be signed by Washington Gov. Jay Inslee.

The $25 million allocation represents the first significant investment in nuclear energy generation by the Washington State Legislature in over a decade.

“The people of the 8th District are energy-savvy consumers who understand the importance of clean nuclear energy,” said Rep. Stephanie Barnard (R – Pasco). “The development of advanced SMRs has been a top priority goal in the Tri-Cities for years, and it’s a top priority for me.”

Energy Northwest said it expects to bring the first Xe-100 module online by 2030.

X-energy’s Xe-100 SMR is a high-temperature gas-cooled reactor. The Maryland-based company said its SMR can address a broad range of uses, including applications that currently rely on fossil fuels to produce steam and heat for processes like manufacturing, petroleum refining and hydrogen production.

Energy Northwest and X-energy have discussed plans for an Xe-100 reactor facility in central Washington since 2020. At one time X-energy’s goal was to have an operational unit by 2028, starting with a 320 MW four-unit Xe-100 power plant in the state.

SCRANTON, Pa. (AP) — Pennsylvania Gov. Josh Shapiro unveiled a plan Wednesday to fight climate change, saying he will back legislation to make power plant owners in the nation’s third-biggest energy-producing state pay for their greenhouse gas emissions and require utilities to buy more electricity from renewable sources.

Such legislation would make Pennsylvania the first major fossil fuel-producing state to adopt a carbon-pricing program. But it is drawing fierce opposition from business interests wary of paying more for power and will face long odds in a Legislature protective of the state’s natural gas industry.

Shapiro’s proposal comes as environmentalists are pressuring him to do more to fight climate change in the nation’s No. 2 gas-producing state and as the state’s highest court considers a challenge to his predecessor’s plan to adopt a carbon-pricing program. It also comes after many of the state’s biggest power polluters, coal-fired plants, have shut down or converted to gas.

At a news conference in Scranton, nicknamed the “Electric City,” Shapiro said his plan will make Pennsylvania competitive in a clean energy economy, improve electricity reliability, cut greenhouse gas emissions and lower electricity bills.

It is long past time for lawmakers to act, he said.

“If they choose to do nothing, they’re choosing to be less competitive in an environment that demands us to bring excellence to the table every single day,” Shapiro said. “They’re choosing to fall behind if they choose to do nothing.”

Under Shapiro’s plan, Pennsylvania would create its own standalone carbon-pricing program, with most of the money paid by polluting power plants — 70% — going to lower consumer electric bills. No one will pay more for electricity and many will pay less, Shapiro said.

Meanwhile, utilities would be required to buy 50% of their electricity from sources that are mostly carbon-free by 2035, up from the state’s current requirement of 18%.

Currently, about 60% of the state’s electricity comes from natural gas-fired power plants, and the 50% renewables requirement could hurt demand for electricity from those plants. Another third of Pennsylvania’s electricity is from nuclear plants — which are not included in the 50% renewables requirement — and the rest from coal and renewables.

Republicans who control the state Senate have pushed to open greater opportunities for natural gas production in Pennsylvania, and have warned that carbon-pricing could raise electricity bills, fray the electricity grid, hurt in-state energy producers and drive new power generation to other states.

“Families are feeling the strain of inflation and increased household expenses, which must be a chief concern when implementing any changes to energy policy,” Senate Majority Leader Joe Pittman, R-Indiana, said in a statement Wednesday.

Shapiro’s administration did not provide many details of his strategy Wednesday, including how much it would reduce greenhouse gases, how much money power plants would pay or how it would affect the average household electric bill.

Patrick Cicero, Pennsylvania’s consumer advocate, said the amount of savings on electric bills will depend on usage — large industrial customers would see more and low-income households would get “significant reductions” because of a planned expansion of the state’s energy-assistance program.

For the average household, “it’s not going to be much,” Cicero said, “but it’s not costing households more. That’s a win-win.”

Neighboring Maryland, New Jersey and New York have set requirements to draw 50% or more of their electricity from renewables by 2030, prompting warnings that Pennsylvania risks falling behind in a clean energy economy.

Robert Bair, president of the Pennsylvania State Building and Construction Trades, whose members work on power plants, refineries and pipelines, said Pennsylvania energy policy must protect workers in the coal and gas industries. But he also said Pennsylvania will lose clean energy jobs to other states if it does nothing.

Heavy energy users and coal-industry businesses slammed Shapiro’s “energy tax” as posing a damaging blow to industries and a fatal blow to the state’s few remaining coal-fired power plants.

The Marcellus Shale Coalition, which represents Pennsylvania’s enormous natural gas industry, was more circumspect. The most pressing challenge is ensuring the electric grid is stable and reliable, said Dave Callahan, the group’s president.

Despite the lack of details, Shapiro’s plan drew statements of support from renewable energy trade associations and environmental advocates.

“Even what the governor has proposed is not enough to meet the needs of addressing the climate crisis, but it’s a huge step forward from where Pennsylvania is now,” said Alex Bomstein, executive director of the Clean Air Council.

Meanwhile, environmental advocates worry about abandoning the plan produced by Shapiro’s predecessor, former Gov. Tom Wolf.

For the time being, a state court has blocked Wolf’s regulation that authorizes Pennsylvania to join the multistate Regional Greenhouse Gas Initiative, which imposes a price and declining cap on carbon dioxide emissions from power plants.

As a candidate for governor, Shapiro had distanced himself from Wolf’s plan — although critics said Shapiro’s plan is similar — and Shapiro wouldn’t say Wednesday whether he’d enforce Pennsylvania’s participation in the regional consortium should the courts uphold it and the Legislature do nothing.

“I’m focused on getting these things passed,” Shapiro said.

The request includes $694.2 million in research and development activities meant to help advance reactor and fuel technologies, address gaps in the domestic nuclear fuel supply chain and utilize the latest artificial intelligence and machine learning tools to optimize performance.

The DOE broke down five areas where the requested budget would be spent:

1. Access to HALEU

NE is requesting $188 million to secure a near-term supply of high-assay low-enriched uranium (HALEU) for DOE-supported research and demonstration projects. 

These efforts include the recovery and downblending of government-owned legacy uranium and ramping up enrichment operations in Piketon, Ohio to help make limited quantities available.  

The funding is meant to complement the DOE’s longer-term strategy to expand its domestic enrichment capacity through purchase agreements with industry partners to help spur demand for additional HALEU production.  

The recently passed FY24 spending bill directed $2.72 billion to further build out a low-enriched uranium and advanced nuclear fuel supply chain.

2. Developing new reactor technologies

The FY25 request includes $142.5 million to support the continued execution of five advanced reactor projects supported through DOE’s Advanced Reactor Demonstration Program.  

NE is also requesting $56 million to establish new testing facilities at the national labs, including $12 million to finish the construction of the NRIC DOME at Idaho National Laboratory.  

DOME will be the world’s first microreactor test bed and could start testing designs as soon as 2026.

The funding also includes $16.5 million for DOE’s MARVEL microreactor testing platform to complete the fabrication of its fuel and key components.  

NE is also requesting more than $18 million to initiate construction of the LOTUS testbed that will be used to test new technologies to generate data required for design and licensing.  

3. Boosting university R&D

NE is requesting $143 million to support emerging technologies developed by U.S. universities, colleges, and small businesses. 

The funding will also be used for university infrastructure improvements and fuel services, along with workforce development activities such as scholarship and fellowship opportunities.  

NE is getting closer to eclipsing the $1 billion funding mark with more than $990 million awarded to colleges and universities across the country since 2009.  

4. Additive manufacturing and AI

The FY25 request also includes $32 million to advance the use of digital tools and manufacturing methods to strengthen nuclear supply chains and help optimize reactor performance.

This funding includes $17 million to support the qualification of additively manufactured materials for use in nuclear reactors and $9 million to develop and demonstrate sensors, instrumentation, and control systems, including potential ways to apply artificial intelligence and machine learning tools to advanced reactor designs and operations.

DOE says the two technologies combined could drastically reduce the time it takes to test, qualify, and deploy new reactor components and fuels. 

The remaining $6 million will address high-priority supply chain needs for the near-term deployment of advanced reactors. 

5. Deploying U.S. reactors internationally

Finally, the FY25 request includes $8 million to support several U.S. international projects, including providing workforce development, training, and technical expertise to new and emerging nuclear energy countries in Africa, Asia, and Central and Eastern Europe.  

The funding will be used to establish regional clean energy training centers in key markets to provide capacity-building and professional development opportunities in regions looking to develop or grow their civil nuclear programs. 

The full budget request can be read here.

The THETA testing campaign is focused on the key thermal-hydraulic behavior of Oklo’s fast fission reactor design. Oklo says a better understanding of key thermal-hydraulic behavior enables design optimizations while providing high-fidelity data using high-fidelity instrumentation.

“Argonne’s leadership and technical expertise have been pivotal to THETA’s success, and the completion of the second phase of testing is a huge accomplishment,” said Patrick Everett, Deputy Senior Director of Product at Oklo. “THETA has and will continue to play a major role in Oklo’s testing endeavors to support our commercialization plans for our Aurora Powerhouses”

Oklo shared costs for the work done at Argonne National Laboratory with funding from a Department of Energy Gateway for Accelerated Innovation in Nuclear voucher.

Last month, Oklo announced the signing of a lands right agreement with the non-profit Southern Ohio Diversification Initiative (SODI) for land including options for the siting of two plants. The company recently announced that the U.S. Department of Energy (DOE) reviewed and approved the Safety Design Strategy (SDS) for its Aurora Fuel Fabrication Facility at Idaho National Laboratory (INL).

The Aurora Fuel Fabrication Facility is being designed to demonstrate the reuse of recovered nuclear material to support Oklo’s planned commercial advanced fission power plant demonstration at INL.

Though coal wasn’t specifically named in a Senate bill that seeks to make Utah an “energy independent” state, the resource was front and center in one of the hottest debates during the last days of the legislative session. The aim of the bills was to keep coal plants from “prematurely” closing, sponsors said, and to not fall in the same “trap” as states like California, which are aggressively pursuing a transition to a cleaner energy grid.

The approved SB224, Energy Independence Amendments, requires the Public Service Commission to change the factors it considers when making decisions on connecting or closing energy resources. One of them is presuming that the cost of “proven” significant energy resources are reasonable. While other parties may challenge that assumption, lawmakers and advocates argue that this not only prioritizes fossil fuels, but breaks a regulatory compact that has kept energy rates low in Utah.

The bill, House sponsor Rep. Carl Albrecht, R-Richfield, said, directs the commission to assume control over the available capacity in Utah plants, as West Coast states renounce coal. 

“As the state grows, this excess capacity can be used in Utah or sold into the market to customers who need reliable, dispatchable power at very attractive rates and keep rates low in the long run for us,” Albrecht told the House on the last day of the session. 

The bill now awaiting the governor’s signature was criticized by lawmakers on both sides of the aisle who, like Rep. Joel Briscoe, D-Salt Lake City, who argued that the legislation is betting that other states mentioned in the debate, such as California, Washington and Oregon, won’t be able to meet their energy needs with cleaner resources, which are emerging in the market. 

That’s a bet that the California Energy Commission predicts won’t pay off. California is in pursuit of achieving 100% clean electricity by 2045 and its policies wouldn’t allow the state to purchase new power from coal plants, including in Utah. 

“California’s investor-owned utilities, which serve a large swath of the state, are prohibited by law from entering into contracts to purchase coal power,” the California Energy Commission said in a statement. 

Data from 2021 shows that 59% of retail electricity sales in California came from non-fossil fuel sources, such as wind, solar, hydro and nuclear power, a rise from the 41% the state had in 2013. 

Still, California, which shares some of the most prominent transmission lines with Utah coal plants, is doing its own in-house emergency planning to use fossil fuels as a backup in extreme weather, agreeing to extend operations at three natural gas plants in Southern California.

Rate increase prediction

During the bill’s House debate, lawmakers from both parties argued that large monopolies — such as utilities — don’t naturally keep rates low. However, the state has a regulating mechanism in which the Public Service Commission requires utilities to demonstrate they are choosing the least expensive mix of power that meets the state’s demand.

Before the bill passed, the burden to show that proof relied on the utility, Rep. Ray Ward, R-Bountiful said. The new policy turns that around.

“We’re just going to presume that if you’re burning coal, your costs are reasonable. Utilities won’t have to show that it is the least expensive to the ratepayers,” Ward said to the House. “And (the bill) says that that presumption can only be challenged by an outside party, who shows that those costs are unreasonable, an outside party that does not have access to the represented utility.” 

Though coal has served the state as the cheapest option for ratepayers, it’s difficult to predict whether it will remain so in the next decades, he said, and the state should be careful before walking away from a regulatory framework that works.

“People will be able to draw a straight line between those rate increases and the vote we take in this body today,” said Briscoe, who unsuccessfully tried to strike that new policy, “because this upends decades of work on the relationship between the utility and the ratepayers in Utah.” 

Rate raises are among the repercussions that the Utah Office of Consumer Service warned about in a public comment, explaining that the rule would shift risks away from the utility to customers.

“This fundamentally shifts utility regulation,” said Michele Beck, director of the office, “and it’s not going to be in a way that benefits customers, you’re going to see higher rates from this.”

Advocates from the Sierra Club added that trying to keep coal plants open is “uneconomical,” as data from PacifiCorp shows that 60% of its plants are more expensive to run than to replace with other sources.

Albrecht doesn’t see how that could be the case for Utah, though. 

“Most people think that if we keep these plants, it’ll raise rates, and that’s absolutely not true,” he said, “because the baseload energy that we have, which is coal and gas, has kept our rates lower.”

Though he has been a fierce defender of coal, Albrecht doesn’t consider himself “a radical coal guy,” as he drives a hybrid car and installed solar panels on his roof. Besides helping run SB224, Albrecht sponsored other bills that could benefit cleaner energy sources, like geothermal, via tax credits. But, as of now, he said, coal and natural gas are what will keep the lights on.

Keeping coal running when others move to intermittent sources like wind and solar, he said, would allow Utah to see its excess power on the market at a premium price, which would lower rates to Utah customers.

To some advocates who said that maintaining decades-old facilities would be expensive for the state, Albrecht said that over the years, they have been maintained “like your best historical race car.”

The quest for energy independence

When legislators speak about energy independence, they don’t mean isolating the grid in a Texas-like model, said Harry Hansen, deputy director at the Utah Office of Energy Development.

The Texas isolated grid system, designed to avoid federal regulation, affected millions during a severe winter storm in 2021 because the state had limited ways to receive help from its neighbors.

“The goal is to be able to sustain our own style of living and our own needs related to energy, not just electricity,” Hansen said. “So that we have that measure of cushioning, I guess, against any potential issues geopolitically.”

Albrecht agreed with that, arguing that Utah’s grid is interconnected with its surrounding states in the West. 

“All we’re saying is that we want to have enough energy for Utah customers,” he said. “We don’t want to be like Texas was and we want to be able to provide energy to other states who are making stupid decisions by going totally renewable.”

Utah’s energy production has been in decline since 2015, turning the state from an energy exporter to an importer in 2020, data from 2021 shows. “This new situation continued into 2021, with an even larger differential, and is predicted to continue in the near term,” a website associated with the Office of Energy Development reads. 

The state’s portfolio changed in the last two decades, going from 94% of coal-fueled electricity in 2000 to 57% in 2022. Renewables represented 15% of the grid’s contribution — up from 3% — while natural gas grew from 3% to 28%.

Hansen said that speaking about coal prioritization is a bit of a “mischaracterization.” It just so happens that coal fits the bills’ parameters of affordability, reliability and dispatchability, he said. 

Though other sources, such as geothermal have the potential to have a bigger capability, “right now the only baseload sources that Utah has are small amounts of hydroelectric or natural gas, (but mostly) coal here in Utah,” Hansen said.

Whenever those resources catch up with established resources, Albrecht believes the state could be able to revisit the newly approved energy policies. But more development in energy storage at a utility scale is needed to be able to sustain intermittent sources such as solar and wind.

“It’s got to be able to carry and store the resource for a day, a week, two weeks,” he said, “so that it can be released into the system at the time of the peak of the system.” 

Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence.

TOKYO (AP) — Japan on Monday marked 13 years since a massive earthquake and tsunami hit the country’s northern coasts. Nearly 20,000 people died, whole towns were wiped out and the Fukushima Daiichi nuclear power plant was destroyed, creating deep fears of radiation that linger today. As the nation observes the anniversary, the AP explains what is happening now at the plant and in neighboring areas.

A magnitude 9.0 earthquake struck on March 11, 2011, causing a tsunami that battered northern coastal towns in Iwate, Miyagi and Fukushima prefectures. The tsunami, which topped 15 meters (50 feet) in some areas, slammed into the nuclear plant, destroying its power supply and fuel cooling systems, and causing meltdowns at reactors No. 1, 2 and 3.

Hydrogen explosions caused massive radiation leaks and contamination in the area.

The operator, Tokyo Electric Power Company Holdings, says that the tsunami couldn’t have been anticipated. Government and independent investigations and some court decisions have said the accident was the result of human error, safety negligence, lax oversight by regulators and collusion.

Japan has since introduced stricter safety standards and at one point shifted to a nuclear energy phaseout. Prime Minister Fumio Kishida’s government reversed that policy and has accelerated restarts of workable reactors to maintain nuclear power as a main source of Japan’s power supply.

A deadly Jan. 1 earthquake in Japan’s northcentral region destroyed many homes and roads but didn’t damage an idled nuclear power plant. Even so, it caused worry that current evacuation plans that solely focus on radiation leaks could be unworkable.

The nation marked a moment of silence at 2:46 p.m. Monday, with Kishida attending a memorial in Fukushima.

WHAT HAPPENED TO PEOPLE IN THE AREA?

About 20,000 of more than 160,000 evacuated residents across Fukushima still haven’t returned home.
Decontamination work before the Tokyo Olympics meant to showcase Fukushima’s recovery led to the elimination of some no-go zones, but they remain in seven of 12 towns that had been fully or partially off-limits.

In Futaba, the hardest-hit town and a co-host of the Fukushima Daiichi plant, a small area was opened in 2022. About 100 people, or 1.5% percent of the pre-disaster population, have returned to live. The other host town, Okuma, which along with Futaba sacrificed part of its land to build an interim storage site for nuclear waste gathered from the decontamination, has seen 6% of its former residents return.

Annual surveys show the majority of evacuees have no intention of returning home, citing lack of jobs, schools and lost communities, as well as radiation concerns.

Residents who have raised radiation worries or linked it to their health problems have come under attack for hurting Fukushima’s reputation.

The disaster-hit towns, including those in Iwate and Miyagi prefectures, have seen sharp population drops.

Fukushima Gov. Masao Uchibori said on NHK TV that a growing number of young people want to move to Fukushima to open businesses or help in the reconstruction, and he expressed hope that more residents will return.

WHAT ABOUT TREATED RADIOACTIVE WATER DISCHARGES?

Last August, Fukushima Daiichi began discharging treated water into the sea, and is currently releasing a fourth 7,800-ton batch of treated water. So far, daily seawater sampling results have met safety standards. The plan has faced protests from local fishers and neighboring countries, especially China, which has banned Japanese seafood imports

Fukushima Daiichi has struggled to handle the contaminated water since the 2011 meltdowns. TEPCO says the start of the process is a milestone and removing the tanks is crucial to make space for facilities needed as decommissioning progresses.

The contaminated cooling water is pumped up, treated and stored in about 1,000 tanks. The government and TEPCO say the water is diluted with massive seawater before release, making it safer than international standards.

WHAT ABOUT LOCAL FISHING?

Despite earlier fears that the water discharge would further hurt Fukushima’s hard-hit fishing industry, they have not damaged its reputation domestically. China’s ban on Japanese seafood, which mostly hit scallop exporters in Hokkaido, apparently prompted Japanese consumers to eat more Fukushima seafood.

Sampling and monitoring by the International Atomic Energy Agency have also boosted confidence in local fish.

Fukushima fishing returned to normal operations in 2021, and the local catch is now about one-fifth of its pre-disaster level because of a decline in the fishing population and smaller catch sizes.

The government has earmarked 10 billion yen ($680 million) to support Fukushima fisheries.

ANY PROGRESS REMOVING MELTED FUEL?

The contents of the three reactors is still largely a mystery. Little is known, for instance, about the melted fuel’s condition or exactly where it’s located in the reactors. Not even a spoonful of the fuel has been removed.

About 880 tons of melted nuclear fuel remain inside the three damaged reactors, and Japanese officials say removing it would take 30-40 years. Experts call that timeline overly optimistic. The amount of melted fuel is 10 times that removed from Three Mile Island following its 1979 partial core melt.

Robotic probes have glimpsed inside the three reactors, but their investigation has been hampered by technical glitches, high radiation and other complications.

It’s crucial for officials to understand the data from melted debris so they can make a plan to remove it safely. TEPCO aims to get the first sample out later this year from the least-damaged No. 2 reactor.

TEPCO has been trying to get the sample by using a robotic arm. Officials have struggled to get the robot past the wreckage, and hope that by October they can use a simpler device that looks like a fishing rod.

The fuel in the worst-damaged No. 1 reactor mostly fell from the core to the bottom of its primary containment vessel. Some of it penetrated and mixed with the concrete foundation, making removal extremely difficult.

In February, the plant made its first drone flight into the primary containment vessel to investigate the melted debris and examine how the fuel initially fell from the core. But a second day of exploration was canceled because a data transmission robot failed.

IS A 2051 COMPLETION POSSIBLE?

The government has stuck to its initial target for a completed decommissioning by 2051, but it hasn’t defined what that means.

The lack of data, technology and plans on what to do with the radioactive melted fuel and other nuclear waste makes it difficult to understand what’s in store for the plant and surrounding areas when the cleanup ends, according to TEPCO’s decommissioning company chief, Akira Ono.

An overly ambitious schedule could result in unnecessary radiation exposure for plant workers and excess environmental damage, experts say.

Under the an MOU signed by the companies, Fluor will design the plant for Longview Fusion Energy Systems. The two partnered in 2023 and signed a memorandum of understanding (MOU) to leverage Fluor’s experience in developing and constructing large, complex facilities. Fluor will provide preliminary design and engineering to support the development of Longview’s fusion-powered plant.

According to Longview, their laser fusion power plants have a capacity of between 1,000 and 1,600 MW. They are able to power the needs of a small city or provide process heat or power to drive industrial production of the materials needed for operational necessities like steel, fertilizer and hydrogen fuel.

Longview says it does not need to build a physics demonstration facility, and, with its partner Fluor, can focus on designing and building the world’s first laser fusion energy plant.

“We are building on the success of the NIF, but the Longview plant will use today’s far more efficient and powerful lasers and utilize additive manufacturing and optimization through AI,” says Valerie Roberts, Longview’s Chief Operating Officer and former NIF construction/project manager.

National Ignition Facility

The planning for the laser fusion plant was enabled by the breakthroughs in fusion energy gain at Lawrence Livermore National Laboratory’s National Ignition Facility (NIF).

“Laser fusion energy gain has been demonstrated many times over the last 15 months, and the scientific community has verified these successes,” said Edward Moses, Longview’s CEO and former director of the NIF. “Now is the time to focus on making this new carbon-free, safe, and abundant energy source available to the nation as soon as possible.”

According to the Lawrence Livermore National Laboratory, in a NIF ignition experiment, a tiny capsule containing two forms of hydrogen is suspended inside a cylindrical x-ray “oven” called a hohlraum.

NIF’s powerful lasers heat the hohlraum to temperatures of more than 3 million degrees Celsius, resulting in x-rays heating up and blowing off the surface of the target capsule. This causes a rocket-like implosion that compresses and heats the fuel to extreme temperatures and densities until the hydrogen atoms fuse, releasing energy.

In December 2022, the National Ignition Facility achieved fusion ignition, a fusion first with an energy production greater than the input energy.

These states include: Arizona, Colorado, Kentucky, Maryland, Montana, North Carolina, Pennsylvania, Utah, West Virginia, Wyoming and Wisconsin. 

Notably, TerraPower plans to build its Natrium reactor near a retiring coal plant in Kemmerer, Wyoming.

A 2022 DOE report found that more than 300 existing and retired coal power plant sites could convert to nuclear, dramatically increasing dispatchable, carbon-free energy as the country strives to meet its net-zero emissions goal by 2050. The department said each plant could match the size of the site being converted and help increase nuclear capacity by more than 250 GW — nearly tripling its current capacity of 95 GW. 

The DOE report also found that new nuclear plants could save up to 35% on construction costs depending on how much of the existing site assets could be repurposed from retired coal power plants. These assets include the existing land, the coal plant’s electrical equipment (transmission connection, switchyard, etc.) and civil infrastructure, such as roads and buildings.

DOE’s Gateway for Accelerated Innovation in Nuclear (GAIN) is conducting three feasibility studies to assess different aspects of repurposing coal power plant sites with nuclear power. 

The proposed rule, to be published in the Federal Register in about six months, would create a new Part 53 section under the NRC’s regulations as an alternative to the existing, large light-water reactor licensing approaches under Parts 50 and 52.

“This proposed rule leverages significantly more risk insights than our existing regulatory framework in making safety determinations,” said NRC Chair Christopher Hanson. “Applicants can use our existing regulations today, but this proposed rule will provide future nuclear developers a clear, additional pathway for licensing.”

The rule, in meeting the requirements of the Nuclear Energy Innovation and Modernization Act, would give plant designers and plant operators flexibility in determining how their nuclear power plant will meet safety criteria, NRC said.

It would set out criteria in areas including reactor siting requirements; analyzing potential accidents; defining safety functions; categorizing structures, systems, and components; addressing construction and manufacturing requirements; providing defense in depth; and protecting the public and plant workers during normal operations.

The proposed rule also would modify agency regulations for operator licensing, employee fitness-for-duty, physical security and site access authorization.

NRC staff said it has conducted extensive public engagement on the proposed rule and plans to seek public feedback when the rule is issued later this year.