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Power-to-gas converts surplus renewable electricity into green hydrogen or synthetic methane via electrolysis and methanation, enabling seasonal energy storage, grid balancing, hydrogen injection into gas pipelines, and decarbonization of heat, transport, and industry.

Key Points

Power-to-gas turns excess renewable power into hydrogen or methane for storage, grid support, and clean fuel.

✅ Enables hydrogen injection into existing natural gas networks

✅ Balances grids and provides seasonal energy storage capacity

✅ Supplies low-carbon fuels for industry, heat, and heavy transport

Last month Denmark’s biggest energy firm, Ørsted, said wind farms it is proposing for the North Sea will convert some of their excess power into gas. Electricity flowing in from offshore will feed on-shore electrolysis plants that split water to produce clean-burning hydrogen, with oxygen as a by-product. That would supply a new set of customers who need energy, but not as electricity. And it would take some strain off of Europe’s power grid as it grapples with an ever-increasing share of hard-to-handle EU wind and solar output on the grid.

Turning clean electricity into energetic gases such as hydrogen or methane is an old idea that is making a comeback as renewable power generation surges and crowds out gas in Europe. That is because gases can be stockpiled within the natural gas distribution system to cover times of weak winds and sunlight. They can also provide concentrated energy to replace fossil fuels for vehicles and industries. Although many U.S. energy experts argue that this “power-to-gas” vision may be prohibitively expensive, some of Europe’s biggest industrial firms are buying in to the idea.

European power equipment manufacturers, anticipating a wave of renewable hydrogen projects such as Ørsted’s, vowed in January that, as countries push for hydrogen-ready power plants across Europe, all of their gas-fired turbines will be certified by next year to run on up to 20 percent hydrogen, which burns faster than methane-rich natural gas. The natural gas distributors, meanwhile, have said they will use hydrogen to help them fully de-carbonize Europe’s gas supplies by 2050.

Converting power to gas is picking up steam in Europe because the region has more consistent and aggressive climate policies and evolving electricity pricing frameworks that support integration. Most U.S. states have goals to clean up some fraction of their electricity supply; coal- and gas-fired plants contribute a little more than a quarter of U.S. greenhouse gas emissions. In contrast, European countries are counting on carbon reductions of 80 percent or more by midcentury—reductions that will require an economywide switch to low-carbon energy.

Cleaning up energy by stripping the carbon out of fossil fuels is costly. So is building massive new grid infrastructure, including transmission lines and huge batteries, amid persistent grid expansion woes in parts of Europe. Power-to-gas may be the cheapest way forward, complementing Germany’s net-zero roadmap to cut electricity costs by a third. “In order to reach the targets for climate protection, we need even more renewable energy. Green hydrogen is perceived as one of the most promising ways to make the energy transition happen,” says Armin Schnettler, head of energy and electronics research at Munich-based electric equipment giant Siemens.

Europe already has more than 45 demonstration projects to improve power-to-gas technologies and their integration with power grids and gas networks. The principal focus has been to make the electrolyzers that convert electricity to hydrogen more efficient, longer-lasting and cheaper to produce.

The projects are also scaling up the various technologies. Early installations converted a few hundred kilowatts of electricity, but manufacturers such as Siemens are now building equipment that can convert 10 megawatts, which would yield enough hydrogen each year to heat around 3,000 homes or fuel 100 buses, according to financial consultancy Ernst & Young.

The improvements have been most dramatic for proton-exchange membrane electrolyzers, which are akin to the fuel cells used in hydrogen vehicles (but optimized to produce hydrogen rather than consume it). The price of proton-exchange electrolyzers has dropped by roughly 40 percent during the past decade, according to a study published in February in Nature Energy. They are also five times more compact than older alkaline electrolysis plants, enabling onsite hydrogen production near gas consumers, and they can vary their power consumption within seconds to operate on fluctuating wind and solar generation.

Many European pilot projects are demonstrating “methanation” equipment that converts hydrogen to methane, too, which can be used as a drop-in replacement for natural gas. Europe’s electrolyzer plants, however, are showing that methanation is not as critical to the power-to-gas vision as advocates long believed. Many electrolyzers are injecting their hydrogen directly into natural gas pipelines—something that U.S. gas firms forbid—and they are doing so without impacting either the gas infrastructure or natural gas consumers.

Europe’s first large-scale hydrogen injection began in eastern Germany in 2013 at a two-megawatt electrolyzer installed by Essen-based power firm E.ON. Germany has since ratcheted up the amount of hydrogen it allows in natural gas lines from an initial 2 percent by volume to 10 percent, in a market where renewables now outpace coal and nuclear in Germany, and other European states have followed suit with their own hydrogen allowances. Christopher Hebling, head of hydrogen technologies at the Freiburg-based Fraunhofer Institute for Solar Energy Systems, predicts that such limits will rise to the 20-percent level anticipated by Europe’s turbine manufacturers.

Moving renewable hydrogen and methane via natural gas pipelines promises to cut the cost of switching to renewable energy. For example, gas networks have storage caverns whose reserves could be tapped to run gas-fired electric generation power plants during periods of low wind and solar output. Hebling notes that Germany’s gas network can store 240 terawatt-hours of energy—roughly 25 times more energy than global power grids can presently store by pumping water uphill to refill hydropower reservoirs. Repurposing gas infrastructure to help the power system could save European consumers 138 billion euros ($156 billion) by 2050, according to Dutch energy consultancy Navigant (formerly Ecofys).

For all the pilot plants and promise, renewable hydrogen presently supplies a tiny fraction of Europe’s gas. And, globally, around 4 percent of hydrogen is supplied via electrolysis, with the bulk refined from fossil fuels, according to the International Renewable Energy Agency.

Power-to-gas is catching up, however. According to the February Nature Energy study, renewable hydrogen already pays for itself in some niche applications, and further electrolyzer improvements will progressively extend its market. “If costs continue to decline as they have done in recent years, power-to-gas will become competitive at large scale within the next decade,” says study co-author Gunther Glenk, an economist at the Technical University of Munich.

Glenk says power-to-gas could scale up faster if governments guaranteed premium prices for renewable hydrogen and methane, as they did to mainstream solar and wind power.

Tim Calver, an energy storage researcher turned consultant and Ernst & Young’s executive director in London, agrees that European governments need to step up their support for power-to-gas projects and markets. Calver calls the scale of funding to date, “not proportionate to the challenge that we face on long-term decarbonization and the potential role of hydrogen.”

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Alberta Last-Resort Power Rate Reform outlines consumer protection against market volatility, price spikes, and wholesale rate swings, promoting fixed-rate plans, price caps, transparency, and stable pricing mechanisms within Alberta's deregulated power market.

Key Points

Alberta Last-Resort Power Rate Reform seeks stable, transparent pricing and stronger consumer protections.

✅ Caps or hedges shield bills from wholesale price spikes

✅ Expand fixed-rate options and enrollment nudges

✅ Publish clear, real-time pricing and market risk alerts

Alberta’s electricity market is facing growing instability, with rising prices leaving many consumers struggling. The province's rate of last resort, a government-set price for people who haven’t chosen a fixed electricity plan, has become a significant concern. Due to volatile market conditions, this rate has surged, causing financial strain for households. Experts, like energy policy analyst Blake Shaffer, argue that the current market structure needs reform. They suggest creating more stability in pricing, ensuring better protection for consumers against unexpected price spikes, and addressing the flaws that lead to market volatility.

As electricity prices climb, many consumers are feeling the pressure. In Alberta, where energy deregulation is the norm in the electricity market, people without fixed-rate plans are automatically switched to the last-resort rate when their contracts expire. This price is based on fluctuating wholesale market rates, which can spike unexpectedly, leaving consumers vulnerable to sharp price increases. For those on tight budgets, such volatility makes it difficult to predict costs, leading to higher financial stress.

Blake Shaffer, a prominent energy policy expert, has been vocal about the need to address these issues. He has highlighted that while some consumers benefit from fixed-rate plans, with experts urging Albertans to lock in rates when possible, those who cannot afford them or who are unaware of their options often find themselves stuck with the unpredictable last-resort rate. This rate can be substantially higher than what a fixed-plan customer would pay, often due to rapid shifts in energy demand and supply imbalances.

Shaffer suggests that the province’s electricity market needs a restructuring to make it more consumer-friendly and less vulnerable to extreme price hikes. He argues that introducing more transparency in pricing and offering more stable options for consumers through new electricity rules could help. In addition, there could be better incentives for consumers to stay informed about their electricity plans, which would help reduce the number of people unintentionally placed on the last-resort rate.

One potential solution proposed by Shaffer and others is the creation of a more predictable and stable pricing mechanism, though a Calgary electricity retailer has urged the government to scrap an overhaul, where consumers could have access to reasonable rates that aren’t so closely tied to the volatility of the wholesale market. This could involve capping prices or offering government-backed insurance against large price fluctuations, making electricity more affordable for those who are most at risk.

The increasing reliance on market-driven prices has also raised concerns about Alberta’s energy policy changes and overall direction. As a province with a large reliance on oil and gas, Alberta’s energy sector is tightly connected to global energy trends. While this has its benefits, it also means that Alberta’s electricity prices are heavily influenced by factors outside the control of local consumers, such as geopolitical issues or extreme weather events. This makes it hard for residents to predict and plan their energy usage and costs.

For many Albertans, the current state of the electricity market feels precarious. As more people face unexpected price hikes, calls for a market overhaul continue to grow louder across Alberta. Shaffer and others believe that a new framework is necessary—one that balances the interests of consumers, the government, and energy companies, while ensuring that basic energy needs are met without overwhelming households with excessive costs.

In conclusion, Alberta’s last-resort electricity rate system is an increasing burden for many. While some may benefit from fixed-rate plans, others are left exposed to market volatility. Blake Shaffer advocates for reform to create a more stable, transparent, and affordable electricity market, one that could better protect consumers from the high risks associated with deregulated pricing. Addressing these challenges will be crucial in ensuring that energy remains accessible and affordable for all Alberta residents.

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EPA Power Plant Emissions Rule proposes strict greenhouse gas limits for coal and gas units, leveraging carbon capture (CCS) under the Clean Air Act to cut CO2 and accelerate decarbonization of the U.S. grid.

Key Points

A proposed EPA rule setting CO2 limits for coal and gas plants, using CCS to cut power-sector greenhouse gases.

✅ Applies to existing and new coal and large gas units

✅ Targets near-zero CO2 by 2038 via CCS or retirement

✅ Cites grid, health, and climate benefits; faces legal challenges

The Biden administration has proposed new limits on greenhouse gas emissions from coal- and gas-fired power plants, its most ambitious effort yet to roll back planet-warming pollution from the nation’s second-largest contributor to climate change.

A rule announced by the Environmental Protection Agency could force power plants to capture smokestack emissions using a technology that has long been promised but is not used widely in the United States, and arrives amid changes stemming from the NEPA rewrite that affect project reviews.

“This administration is committed to meeting the urgency of the climate crisis and taking the necessary actions required,″ said EPA Administrator Michael Regan.

The plan would not only “improve air quality nationwide, but it will bring substantial health benefits to communities all across the country, especially our front-line communities ... that have unjustly borne the burden of pollution for decades,” Regan said in a speech at the University of Maryland.

President Joe Biden, whose climate agenda includes a clean electricity standard as a key pillar, called the plan “a major step forward in the climate crisis and protecting public health.”

If finalized, the proposed regulation would mark the first time the federal government has restricted carbon dioxide emissions from existing power plants, following a Trump-era replacement of Obama’s power plant overhaul, which generate about 25% of U.S. greenhouse gas pollution, second only to the transportation sector. The rule also would apply to future electric plants and would avoid up to 617 million metric tons of carbon dioxide through 2042, equivalent to annual emissions of 137 million passenger vehicles, the EPA said.

Almost all coal plants — along with large, frequently used gas-fired plants — would have to cut or capture nearly all their carbon dioxide emissions by 2038, the EPA said, a timeline that echoed concerns raised during proposed electricity pricing changes in the prior administration. Plants that cannot meet the new standards would be forced to retire.

The plan is likely to be challenged by industry groups and Republican-leaning states, much like litigation over the Affordable Clean Energy rule unfolded in recent years. They have accused the Democratic administration of overreach on environmental regulations and warn of a pending reliability crisis for the electric grid. The power plant rule is one of at least a half-dozen EPA rules limiting power plant emissions and wastewater treatment rules.

“It’s truly an onslaught” of government regulation “designed to shut down the coal fleet prematurely,″ said Rich Nolan, president and CEO of the National Mining Association.

Regan denied that the power plant rule was aimed at shutting down the coal sector, but acknowledged — even after the end to the 'war on coal' rhetoric — “We will see some coal retirements.”

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Floatgen Floating Offshore Wind Turbine exports first kWh to France's grid from SEM-REV off Le Croisic, showcasing Ideol's concrete floating foundation by Bouygues and advancing marine renewable energy leadership ambitions.

Key Points

A grid-connected demo turbine off Le Croisic, proving Ideol's floating foundation at SEM-REV.

✅ First power exported to French grid from SEM-REV site

✅ Ideol concrete floating base built by Bouygues

✅ Demonstrator can supply up to 5,000 inhabitants

Floating offshore wind turbine Floatgen, the first offshore wind turbine installed off the French coast, exported its first KWh to the electricity grid, echoing the offshore wind power milestone experienced by U.S. customers recently.

The connection of the electricity export cable, similar in ambition to the UK's 2 GW substation program, and a final series of tests carried out in recent days enabled the Floatgen wind turbine, which is installed 22 km off Le Croisic (Loire-Atlantique), to become fully operational on Tuesday 18 September.

This announcement is a highly symbolic step for the partners involved in this project. This wind turbine is the first operational unit of the floating foundation concept patented by Ideol and built in concrete by Bouygues Travaux Publics. A second unit of the Ideol foundation will soon be operational off Japan. For Centrale Nantes, this is the first production tool and the first injection of electricity into its export cable at its SEM-REV test site dedicated to marine renewable energies, alongside projects such as the Scotland-England subsea power link that expand transmission capacity (third installation after tests on acoustic sensors and cable weights).

This announcement is also symbolic for France since Floatgen lays the foundation for an industrial offshore wind energy sector and represents a unique opportunity to become the global leader in floating wind, as major clean energy corridors like the Canadian hydropower line to New York illustrate growing demand.

With its connection to the grid, SEM-REV will enable the wind turbine to supply electricity to 5000 inhabitants, and similar integrated microgrid initiatives show how local reliability can be enhanced.

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Natrium small modular reactor pairs a sodium-cooled fast reactor with molten salt storage to deliver load-following, dispatchable nuclear power, enhancing grid flexibility and peaking capacity as TerraPower and GE Hitachi pursue factory-built, affordable deployment.

Key Points

A TerraPower-GE Hitachi SMR joining a sodium-cooled reactor with molten salt storage for flexible, dispatchable power.

✅ 345 MW base; 500 MW for 5.5 hours via thermal storage

✅ Sodium-cooled coolant and molten salt storage enable load-following

✅ Backed by major utilities; factory-built modules aim lower costs

Nuclear power is the Immovable Object of generation sources. It can take days just to bring a nuclear plant completely online, rendering it useless as a tool to manage the fluctuations in the supply and demand on a modern energy grid.  

Now a firm launched by Bill Gates in 2006, TerraPower, in partnership with GE Hitachi Nuclear Energy, believes it has found a way to make the infamously unwieldy energy source a great deal nimbler, drawing on next-gen nuclear ideas — and for an affordable price. 

The new design, announced by TerraPower on August 27th, is a combination of a "sodium-cooled fast reactor" — a type of small reactor in which liquid sodium is used as a coolant — and an energy storage system. While the reactor could pump out 345 megawatts of electrical power indefinitely, the attached storage system would retain heat in the form of molten salt and could discharge the heat when needed, increasing the plant’s overall power output to 500 megawatts for more than 5.5 hours. 

“This allows for a nuclear design that follows daily electric load changes and helps customers capitalize on peaking opportunities driven by renewable energy fluctuations,” TerraPower said. 

Dubbed Natrium after the Latin name for sodium ('natrium'), the new design will be available in the late 2020s, said Chris Levesque, TerraPower's president and CEO.

TerraPower said it has the support of a handful of top U.S. utilities, including Berkshire Hathaway Energy subsidiary Pacificorp, Energy Northwest, and Duke Energy. 

The reactor's molten salt storage add-on would essentially reprise the role currently played by coal- or gas-fired power stations or grid-scale batteries: each is a dispatchable form of power generation that can quickly ratchet up or down in response to changes in grid demand or supply. As the power demands of modern grids become ever more variable with additions of wind and solar power — which only provide energy when the wind is blowing or the sun shining — low-carbon sources of dispatchable power are needed more and more, and Europe is losing nuclear power at a difficult moment for energy security. California’s rolling blackouts are one example of what can happen when not enough power is available to be dispatched to meet peak demand. 

The use of molten salt, which retains heat at extremely high temperatures, as a storage technology is not new. Concentrated solar power plants also collect energy in the form of molten salt, although such plants have largely been abandoned in the U.S. The technology could enjoy new life alongside nuclear plants: TerraPower and GE Hitachi Nuclear are only two of several private firms working to develop reactor designs that incorporate molten salt storage units, including U.K.- and Canada-based developer Moltex Energy.

The Gates-backed venture and its partner touted the "significant cost savings" that would be achieved by building major portions of their Natrium plants through not a custom but an industrial process — a defining feature of the newest generation of advanced reactors is that their parts can be made in factories and assembled on-site — although more details on cost weren't available. Reuters reported earlier that each plant would cost around $1 billion.

NuScale Power

A day after TerraPower and GE Hitachi's unveiled their new design, another nuclear firm — Portland, Oregon-based NuScale Power — announced that the U.S. Nuclear Regulatory Commission (NRC) had completed its final safety evaluation of NuScale’s new small modular reactor design.

It was the first small modular reactor design ever to receive design approval from the NRC, NuScale said. 

The approval means customers can now pursue plans to develop its reactor design confident that the NRC has signed off on its safety aspects. NuScale said it has signed agreements with interested parties in the U.S., Canada, Romania, the Czech Republic, and Jordan, and is in the process of negotiating more. 

NuScale previously said that construction on one of its plants could begin in Utah in 2023, with the aim of completing the first Power Module in 2026 and the remaining 11 modules in 2027.

NuScale
An artist’s rendering of NuScale Power’s small modular nuclear reactor plant. NUSCALE POWER
NuScale’s reactor is smaller than TerraPower’s. Entirely factory-built, each of its Power Modules would generate 60 megawatts of power. The design, typical of advanced reactors, uses pressurized water reactor technology, with one power plant able to house up to 12 individual Power Modules. 

In a sign of the huge amounts of time and resources it takes to get new nuclear technology to the market’s doorstep, NuScale said it first completed its Design Certification Application in December 2016. NRC officials then spent as many as 115,000 hours reviewing it, NuScale said, in what was only the first of several phases in the review process. 

In January 2019, President Donald Trump signed into law the Nuclear Energy Innovation and Modernization Act (NEIMA), designed to speed the licensing process for advanced nuclear reactors, and the DOE under Secretary Rick Perry moved to advance nuclear development through parallel initiatives. The law had widespread bipartisan support, underscoring Democrats' recent tentative embrace of nuclear power.

An industry eager to turn the page

After a boom in the construction of massive nuclear power plants in the 1960s and 70s, the world's aging fleet of nuclear plants suffers from rising costs and flagging public support. Nuclear advocates have for years heralded so-called small modular reactors or SMRs as the cheaper and more agile successors to the first generation of plants, and policy moves such as the UK's green industrial revolution lay out pathways for successive waves of reactors. But so far a breakthrough on cost has proved elusive, and delays in development timelines have been abundant. 

Edwin Lyman, the director of nuclear power safety at the Union of Concerned Scientists, suggested on Twitter that the nuclear designs used by TerraPower and GE Hitachi had fallen short of a major innovation. “Oh brother. The last thing the world needs is a fleet of sodium-cooled fast reactors,” he wrote.  

Still, climate scientists view nuclear energy as a crucial source of zero-carbon energy, with analyses arguing that net-zero emissions may be impossible without nuclear in many scenarios, if the world stands a chance at limiting global temperature increases to well below 2 degrees Celsius above pre-industrial levels. Nearly all mainstream projections of the world’s path to keeping the temperature increase below those levels feature nuclear energy in a prominent role, including those by the United Nations and the International Energy Agency (IEA). 

According to the IEA: “Achieving the clean energy transition with less nuclear power is possible but would require an extraordinary effort.”

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Spring Storm Grid Risks highlight tornado outbreaks, flooding, power outages, and transmission disruptions, with NOAA flood outlooks, coal and barge delays, vulnerable nuclear sites, and distribution line damage demanding resilience, reliability, and emergency preparedness.

Key Points

Spring Storm Grid Risks show how tornadoes and floods disrupt power systems, fuel transport, and plants guide resilience.

✅ Tornado outbreaks and derechos damage distribution and transmission

✅ Flooding drives outages via treefall, substation and plant inundation

✅ Fuel logistics disrupted: rail coal, river barges, road access

The storm and tornado outbreak that recently barreled through the US Midwest, South and Mid-Atlantic was a devastating reminder of how much danger spring can deliver, despite it being the “milder” season compared to summer and winter.  

Danger season is approaching, and the country is starting to see the impacts. 

The event killed at least 32 people across seven states. The National Weather Service is still tallying up the number of confirmed tornadoes, which has already passed 100. Communities coping with tragedy are assessing the damage, which so far includes at least 72 destroyed homes in one Tennessee county alone, and dozens more homes elsewhere. 

On Saturday, April 1–the day after the storm struck–there were 1.1 million US utility customers without power, even as EIA reported a January power generation surge earlier in the year. On Monday morning, April 3, there were still more than 80,000 customers in the dark, according to PowerOutage.us. The storm system brought disruptions to both distribution grids–those networks of local power lines you generally see running overhead to buildings–as well as the larger transmission grid in the Midwest, which is far less common than distribution-level issues. 

While we don’t yet have a lot of granular details about this latest storm’s grid impacts, recent shifts in demand like New York City's pandemic power patterns show how operating conditions evolve, and it’s worth going through what else the country might be in for this spring, as well as in future springs. Moreover, there are steps policymakers can take to prepare for these spring weather phenomena and bolster the reliability and resilience of the US power system. 

Heightened flood risk 
The National Oceanic Atmospheric Administration (NOAA) said in a recent outlook that about 44 percent of the United States is at risk of floods this spring, equating to about 146 million people. This includes most of the eastern half of the country, the federal agency said. 

The agency also sees “major” flood risk potential in some parts of the Upper Mississippi River Basin, and relatively higher risk in the Sierra Nevada region, due in part to a historic snowpack in California.  

Multiple components of the power system can be affected by spring floods. 

Power lines – Floods can saturate soil and make trees more likely to uproot and fall onto power lines. This has been contributing to power outages during California’s recent heavy storms–called atmospheric rivers–that started over the winter. In other regions, soil moisture has even been used as a predictor of where power outages will occur due to hurricanes, so that utility companies are better prepared to send line repair crews to the right areas. Hurricanes are primarily a summer and fall phenomenon, and summer also brings grid stress from air conditioning demand in many states, so for now, during spring, they are less of a concern.  

Fuel transport – Spring floods can hinder the transportation of fuels like coal. While it is a heavily polluting fossil fuel that is set to continue declining as a fuel source for US electricity generation, with the EIA summer outlook for wind and solar pointing to further shifts, coal still accounted for roughly 20 percent of the country’s generation in 2022.   

About 70 percent of US coal is transported at least part of the way by trains. The rail infrastructure to transport coal from the Powder River Basin in Montana and Wyoming–the country’s primary coal source–was proven to be vulnerable to extreme floods in the spring of 2011, and even more extreme floods in the spring of 2019. The 2019 floods’ disruptions of coal shipments to power plants via rail persisted for months and into the summertime, also affecting river shipments of coal by barge. In June 2019, hundreds of barges were stalled in the Mississippi River, through which millions of tons of the fossil fuel are normally transported. 

Power plants – Power plants themselves can also be at risk of flooding, since most of them are sited near a source of water that is used to create steam to spin the plants’ turbines, and conversely, low water levels can constrain hydropower as seen in Western Canada hydropower drought during recent reservoir shortfalls. Most US fossil fuel generating capacity from sources like methane gas, which recently set natural gas power records across the grid, and coal utilizes steam to generate electricity. 

However, much of the attention paid to the flood risk of power plant sites has centered on nuclear plants, a key source of low-carbon electricity discussed in IAEA low-carbon electricity lessons that also require a water source for the creation of steam, as well as for keeping the plant cool in an emergency. To name a notable flood example here in the United States–both visually and substantively–in 2011, the Fort Calhoun nuclear plant in Nebraska was completely surrounded by water due to late-spring flooding along the Missouri River. This sparked a lot of concerns because it was just a few months after the March 2011 meltdown of the Fukushima Daiichi nuclear plant in Japan. The public was thankfully not harmed by the Nebraska incident, but this was unfortunately not an isolated incident in terms of flood risks posed to the US nuclear power fleet. 

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