Plan for nuclear storage Is slow to form

By New York Times


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The Energy Department has not finished plans to consolidate storage of nuclear bomb fuel and other high-risk materials now spread among numerous sites, even though the department said in 2005 that it would do so within about a year, according to a recently released Government Accountability Office report.

As a result, the department is spending hundreds of millions of dollars to defend additional sites.

The G.A.O. had reported that the Energy Department was putting off making security improvements at some of the storage sites because the sites were due to be phased out. But the new report makes clear that the goal of shutting down some obsolete weapons and research centers, and simplifying the security job by centralizing “special nuclear material,” as bomb fuel is called, has yet to advance from concept to plan, let alone to finished project.

The Energy Department “has completed only two of the eight implementation plans for consolidating and disposing of special nuclear material,” the new report found, and it cited problems with those two plans.

Representative Joe L. Barton, the Texas Republican who is the ranking member of the House Energy and Commerce Committee and who requested the study, said in a statement: “We’re just trying to get to the point where the D.O.E. has a plan. Two years have passed by since we asked about a plan, and still no plan.”

A spokesman for the National Nuclear Security Administration, part of the Energy Department, did not dispute that planning was moving more slowly than anticipated but said that shipments of some radioactive materials had begun. The spokesman, Bryan Wilkes, said the department had to acquire certification of the storage and shipping containers, institute security and safety requirements, and address legal and environmental impacts.

“Whenever special nuclear materials are moved, a lot of unforeseen challenges arise,” he said in an e-mail message. “When planning an operation of this size and sensitivity, key issues of security, safety, environmental responsibility and public input take precedence over schedules.”

On Oct. 7, 2005, Charles E. Anderson, the principal deputy assistant secretary of environmental management, testified before Mr. Barton, who was then the chairman of the committee, and said he wanted to finish the planning “within a year or two,” and recognized “the urgency to make that closer to a year.” Asked if the department needed more money or other help from Congress to wrap up the planning, Mr. Anderson said no.

The concept is to remove plutonium and highly enriched uranium from Lawrence Livermore National Laboratory, in a part of California that is now largely suburban; surplus plutonium from the Hanford nuclear reservation in Washington State, a site that is mostly being decommissioned; and plutonium-238, used to generate heat for space probes, at Oak Ridge National Laboratory in Tennessee.

Highly enriched uranium from Sandia National Laboratory in New Mexico, and plutonium and uranium-233 from Los Alamos, also in New Mexico, would also be moved. Uranium-233 was manufactured decades ago from thorium, and can be used in weapons but is now considered impractical for that purpose.

The various materials would go to another Tennessee site, Y-12; the Savannah River Site, in South Carolina; Pantex, near Amarillo, Tex.; the Nevada Test Site; and the Idaho National Laboratory.

The report says that one problem is poor coordination among different parts of the department, including the divisions of environmental management, defense programs and nuclear energy. It said that terrorists might invade one of the sites and detonate a weapon, assemble an improvised nuclear explosive from the materials at hand or steal a weapon for use elsewhere.

A Republican staff member on the committee said that some of the plans might face local opposition at some point, but that so little had been done that so far there was little to which to object.

The G.A.O. said the Energy DepartmentÂ’s goal was to finish consolidating the material by 2008, but that this was unlikely.

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Bill Gates’ Nuclear Startup Unveils Mini-Reactor Design Including Molten Salt Energy Storage

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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Is The Global Energy Transition On Track?

Global Decarbonization Strategies align renewable energy, electrification, clean air policies, IMO sulfur cap, LNG fuels, and the EU 2050 roadmap to cut carbon intensity and meet Paris Agreement targets via EVs and efficiency.

 

Key Points

Frameworks that cut emissions via renewables, EVs, efficiency, cleaner marine fuels, and EU policy roadmaps.

✅ Renewables scale as wind and solar outcompete new coal and gas.

✅ Electrification of transport grows as EV costs fall and charging expands.

✅ IMO 2020 sulfur cap and LNG shift cut shipping emissions and particulates.

 

Are we doing enough to save the planet? Silly question. The latest prognosis from the United Nations’ Intergovernmental Panel on Climate Change made for gloomy reading. Fundamental to the Paris Agreement is the target of keeping global average temperatures from rising beyond 2°C. The UN argues that radical measures are needed, and investment incentives for clean electricity are seen as critical by many leaders to accelerate progress to meet that target.

Renewable power and electrification of transport are the pillars of decarbonization. It’s well underway in renewables - the collapse in costs make wind and solar generation competitive with new build coal and gas.

Renewables’ share of the global power market will triple by 2040 from its current level of 6% according to our forecasts.

The consumption side is slower, awaiting technological breakthrough and informed by efforts in countries such as New Zealand’s electricity transition to replace fossil fuels with electricity. The lower battery costs needed for electric vehicles (EVs) to compete head on and displace internal combustion engine (ICE)  cars are some years away. These forces only start to have a significant impact on global carbon intensity in the 2030s. Our forecasts fall well short of the 2°C target, as does the IEA’s base case scenario.

Yet we can’t just wait for new technology to come to the rescue. There are encouraging signs that society sees the need to deal with a deteriorating environment. Three areas of focus came out in discussion during Wood Mackenzie’s London Energy Forum - unrelated, different in scope and scale, each pointing the way forward.

First, clean air in cities.  China has shown how to clean up a local environment quickly. The government reacted to poor air quality in Beijing and other major cities by closing older coal power plants and forcing energy intensive industry and the residential sector to shift away from coal. The country’s return on investment will include a substantial future health care dividend.

European cities are introducing restrictions on diesel cars to improve air quality. London’s 2017 “toxicity charge” is a precursor of an Ultra-Low Emission Zone in 2019, and aligns with UK net-zero policy changes that affect transport planning, to be extended across much of the city by 2020. Paris wants to ban diesel cars from the city centre by 2025 and ICE vehicles by 2030. Barcelona, Madrid, Hamburg and Stuttgart are hatching similar plans.

 

College Promise In California: Community-Wide Efforts To Support Student Success

Second, desulphurisation of global shipping. High sulphur fuel oil (HSFO) meets around 3.5 million barrels per day (b/d) of the total marine market of 5 million b/d. A maximum of 3.5% sulphur content is allowed currently. The International Maritime Organisation (IMO) implements a 0.5% limit on all shipping in 2020, dramatically reducing the release of sulphur oxides into the atmosphere.

Some ships will switch to very low sulphur fuel oil, of which only around 1.4 million b/d will be available in 2020. Others will have to choose between investing in scrubbers or buying premium-priced low sulphur marine gas oil.

Longer-term, lower carbon-intensity gas is a winner as liquefied natural gas becomes fuel of choice for many newbuilds. Marine LNG demand climbs from near zero to 50 million tonnes per annum (tpa) by 2040 on our forecasts, behind only China, India and Japan as a demand centre. LNG will displace over 1 million b/d of oil demand in shipping by 2040.

Third, Europe’s radical decarbonisation plans. Already in the vanguard of emissions reductions policy, the European Commission is proposing to reduce carbon emissions for new cars and vans by 30% by 2030 versus 2020. The targets come with incentives for car manufacturers linked to the uptake of EVs.

The 2050 roadmap, presently at the concept stage, envisages a far more demanding regime, with EU electricity plans for 2050 implying a much larger power system. The mooted 80% reduction in emissions compared with 1990 will embrace all sectors. Power and transport are already moving in this direction, but the legacy fuel mix in many other sectors will be disrupted, too.

Near zero-energy buildings and homes might be possible with energy efficiency improvements, renewables and heat pumps. Electrification, recycling and bioenergy could reduce fossil fuel use in energy intensive sectors like steel and aluminium, and Europe’s oil majors going electric illustrates how incumbents are adapting. Some sectors will cite the risk decarbonisation poses to Europe’s global competitiveness. If change is to come, industry will need to build new partnerships with society to meet these targets.

The 2050 roadmap signals the ambition and will be game changing for Europe if it is adopted. It would provide a template for a global roll out that would go a long way toward meeting UN’s concerns.

 

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Quebec premier inaugurates La Romaine hydroelectric complex

La Romaine Hydroelectric Complex anchors Quebec's hydropower expansion, showcasing Hydro-Québec ingenuity, clean energy, electrification, and grid capacity gains along the North Shore's Romaine River to power industry and nearly 470,000 homes.

 

Key Points

A four-station, $7.4B hydro project on Quebec's Romaine River producing 8 TWh a year for electrification and industry.

✅ Generates 8 TWh yearly, powering about 470,000 homes

✅ Largest Quebec hydro build since James Bay project

✅ Key to clean energy, grid capacity, and electrification

 

Quebec Premier François Legault has inaugurated the la Romaine hydroelectric complex on the province's North Shore.

The newly inaugurated Romaine hydroelectric complex could serve as a model for future projects, such as the Carillon Generating Station investment now planned in the province, Legault said.

"It brings me a lot of pride. It is truly the symbol of Quebec ingenuity," he said as he opened the vast power plant.

Legault was accompanied at today's event by Jean Charest, who was Quebec premier when construction began in 2009, as well as Hydro-Québec president and CEO Michael Sabia. 

La Romaine is comprised of four power stations and is the largest hydro project constructed in the province since the Robert Bourassa generation facility, which was commissioned in 1979. It is the biggest hydro installation since the James Bay project, bolstering Hydro-Québec's hydropower capacity across the grid today.

The construction work for Romaine-4 was supposed to finish in 2020, but it was delayed the COVID-19 pandemic, the death of four workers due to security flaws and soil decomposition problems. 

The $7.4-billion la Romaine complex can produce eight terawatt hours of electricity per year, enough to power nearly 470,000 homes.

It generates its power from the Romaine River, located north of Havre-St-Pierre, Que., near the Labrador border, where long-standing Newfoundland and Labrador tensions over Quebec's projects sometimes resurface today.

Legault said that Quebec still doesn't have enough electricity to meet demand from industry, including recent allocations of electricity for industrial projects across the province, and Quebecers need to consider more ways to boost the province's ability to power future projects. The premier has said previously that demand is expected to surge by an additional 100 terawatt-hours by 2050 — half the current annual output of the provincially owned utility.

Legault's environmental plan of reducing greenhouse gases and achieving carbon neutrality by 2050 hinges on increased electrification and a strategy to wean off fossil fuels provincewide, so the electricity needs for transport and industry will be massive.

An updated strategic plan from Hydro-Quebec will be presented in November outlining those needs, president and CEO Michael Sabia told reporters on Thursday, after recent deals with NB Power underscored interprovincial demand.

Legault said the report will trigger a broader debate on energy transition and how the province can be a leader in the green economy. He said he wasn't ruling out any potential power sources — except for a return to nuclear power at this stage.

 

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Millions at Risk of Electricity Shut-Offs Amid Summer Heat

Summer Heatwave Electricity Shut-offs strain power grids as peak demand surges, prompting load shedding, customer alerts, and energy conservation. Vulnerable populations face higher risks, while cooling centers, efficiency upgrades, and renewables bolster resilience.

 

Key Points

Episodic power cuts during extreme heat to balance grid load, protect infrastructure, and manage peak demand.

✅ Causes: peak demand, heatwaves, aging grid, AC load spikes.

✅ Impacts: vulnerable households, health risks, economic losses.

✅ Solutions: load shedding, cooling centers, efficiency, renewables.

 

As temperatures soar across various regions, millions of households are facing the threat of U.S. blackouts due to strain on power grids and heightened demand for cooling during summer heatwaves. This article delves into the causes behind these potential shut-offs, the impact on affected communities, and strategies to mitigate such risks in the future.

Summer Heatwave Challenges

Summer heatwaves bring not only discomfort but also significant challenges to electrical grids, particularly in densely populated urban areas where air conditioning units and cooling systems, along with the data center demand boom, strain the capacity of infrastructure designed to meet peak demand. As temperatures rise, the demand for electricity peaks, pushing power grids to their limits and increasing the likelihood of disruptions.

Vulnerable Populations

The risk of electricity shut-offs disproportionately affects vulnerable populations, including low-income households, seniors, and individuals with medical conditions that require continuous access to electricity for cooling or medical devices. These groups are particularly susceptible to heat-related illnesses and discomfort when faced with more frequent outages during extreme heat events.

Utility Response and Management

Utility companies play a critical role in managing electricity demand and mitigating the risk of shut-offs during summer heatwaves. Strategies such as load shedding, where electricity is temporarily reduced in specific areas to balance supply and demand, and deploying AI for demand forecasting are often employed to prevent widespread outages. Additionally, utilities communicate with customers to provide updates on potential shut-offs and offer advice on energy conservation measures.

Community Resilience

Community resilience efforts are crucial in addressing the challenges posed by summer heatwaves and electricity shut-offs, especially as Canadian grids face harsher weather that heightens outage risks. Local governments, non-profit organizations, and community groups collaborate to establish cooling centers, distribute fans, and provide support services for vulnerable populations during heat emergencies. These initiatives help mitigate the health impacts of extreme heat and ensure that all residents have access to relief from oppressive temperatures.

Long-term Solutions

Investing in resilient infrastructure, enhancing energy efficiency, and promoting renewable energy sources are long-term solutions to reduce the risk of electricity shut-offs during summer heatwaves by addressing grid vulnerabilities that persist. By modernizing electrical grids, integrating smart technologies, and diversifying energy sources, communities can enhance their capacity to withstand extreme weather events and ensure reliable electricity supply year-round.

Public Awareness and Preparedness

Public awareness and preparedness are essential components of mitigating the impact of electricity shut-offs during summer heatwaves. Educating residents about energy conservation practices, encouraging the use of programmable thermostats, and promoting the importance of emergency preparedness plans empower individuals and families to navigate heat emergencies safely and effectively.

Conclusion

As summer heatwaves become more frequent and intense due to climate change impacts on the grid, the risk of electricity shut-offs poses significant challenges to communities across the globe. By implementing proactive measures, enhancing infrastructure resilience, and fostering community collaboration, stakeholders can mitigate the impact of extreme heat events and ensure that all residents have access to safe and reliable electricity during the hottest months of the year.

 

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Europe Stores Electricity in Natural Gas Pipes

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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Old meters giving away free electricity to thousands of N.B. households

NB Power Smart Meters will replace aging analog meters, boosting billing accuracy, reducing leakage, and modernizing distribution as the EUB considers a $92 million rollout of 360,000 advanced meters for residential and commercial customers.

 

Key Points

NB Power Smart Meters replace analog meters, improving billing accuracy and reducing leakage in the electricity network.

✅ EUB reviewing $92M plan for 360,000 advanced meters

✅ Replaces 98,000 analog units; curbs unbilled kWh

✅ Improves billing accuracy and reduces system leakage

 

Home and business owners with old power meters in New Brunswick have been getting the equivalent of up to 10 days worth of electricity a year or more for free, a multi million dollar perk that will end quickly if the Energy and Utilities Board approves the adoption of smart meters, a move that in other provinces has prompted refusal fees for some holdouts.

Last week the EUB began deliberations over whether to allow NB Power to purchase and install 360,000 new generation smart meters for its residential and commercial customers as part of a $92 million upgrade of its distribution system, even as regulators elsewhere approve major rate changes that affect customer bills.

If approved, that will spell the end to about 98,000 aging electromagnetic or analog meters still used by about one quarter of NB Power customers.  Those are the kind with a horizontal spinning silver disc and clock-face style dials that record consumption 

NB Power lawyer John Furey told the energy and utilities board last week that the utility suspects it loses several million dollars a year to electricity consumed by customers that is not properly recorded by their old meters. It was a central issue in Furey's argument for smart meters amid broader debates over industrial subsidies and debt. (Roger Cosman/CBC)
The analog units, some more than 50 years old and installed back when the late Louis Robichaud and Richard Hatfield were premiers in the 1960's and 1970's - are suspected of doling out millions of kilowatt hours of free power to customers by failing to register all of the current that moves through them.   

"Over time, analog meters slow down and they register lower consumption of electricity than is actually occurring," said NB Power lawyer John Furey last week about the widespread freeloading of power in New Brunswick caused by the old meters.

3 per cent missed
A 2010 report by the independent non-profit Electric Power Research Institute in Palo Alto, California and entered into evidence during NB Power's smart meter hearing said old spinning disc meters generally degrade over time and after 20 years typically fail to register nearly 3 per cent of the power that flows through them.

The average age of analog meters in New Brunswick is much older than that - 31 years - and more than 11,000 of the units are over the age of 40.

"Worn gears, corrosion, moisture, dust, and insects can all cause drag and result in an electromagnetic meter that does not capture the full consumption of the premises," said the report.

The sudden correction to full accounting and billing could naturally surprise these homeowners and even trigger consumer backlash in some cases

- Electric Power Research Institute report
About 94,000 NB residential customers and 3,900 commercial customers have an old meter, according to NB Power records. The group would receive about 40 million kilowatt hours of electricity for free this year  ($5.1 million worth including HST)  if the average unit failed to register 2 percent of the electricity flowing through it, while elsewhere some customers are receiving lump-sum credits on electricity bills.  

That is about $41 in free power for the average residential customer and $322 for the average business.

But, according to the research, there would also be hundreds of customers with meters that have slowed considerably more than the average with 0.3 percent - or close to 300 in NB Power's case -  not counting between 10 and 20 percent of the electricity customers are using. 

NB Power senior Vice President Lori Clark told the EUB stopping the freeloading of power in New Brunswick caused by older meters is in everyone's interest. (Roger Cosman/CBC)
That's potentially $400 in free electricity in a year for a residential customer with average consumption.

"While the average meter might be only slightly slow a few could be significantly so," said the report.

"The sudden correction to full accounting and billing could naturally surprise these homeowners and result in questioning of a new meter, as seen in a shocking $666 bill reported by a Nova Scotia senior." 

The report made the point analog meters can also run fast but called that "less common" meaning that if the EUB approves smart meters, tens of thousands of customers who lose an old meter to a new accurate model will experience higher bills.

'Leakage' reduction
NB Power acknowledges it does not know precisely how much power its older meters give away but said whether it is a little or a lot, ending the freebies is to everyone's benefit. 

"It reduces our inefficiencies, reduces our leakage that we have in the system, so that we are  picking up those unbilled kilowatt hours," said NB Power senior vice president Lori Clark about ending the free power many customers unknowingly enjoy.

Smart meter critics change tone on NB Power's new business case
NB Power's smart meter plan gets major boost with critical endorsements
"Customers benefit from reduced inefficiencies in our system. They benefit from reduced leakage in our system and the fact that those kilowatt hours are being properly billed to the customers that have consumed the kilowatt hours."   

NB Power hopes to win approval of its plan to acquire smart meters by this spring to allow installation beginning in mid 2021, even as some utilities elsewhere have backed away from smart home network projects.

 

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