The curious carbon offset market

Canada Nuclear Power Expansion highlights SMRs, clean energy, net-zero targets, and robust regulation to deliver safe, reliable baseload electricity, spur investment, and economically decarbonize remote communities, mines, and grids across provinces securely.

Key Points

Canada Nuclear Power Expansion grows SMRs and reactors to meet climate targets with safe, reliable baseload power.

✅ Deploys SMRs for remote communities, mines, and industrial sites

✅ Streamlines regulation to ensure safety, trust, and timely approvals

✅ Provides clean, reliable baseload to hit net-zero electricity goals

Canada must expand its nuclear power capacity if it is to reach its climate targets, according to Canadian Minister of Natural Resources Seamus Oregan.

Speaking to the Canadian Nuclear Association’s annual conference, Seamus O’Regan said the industry has to grow.

“As the world tackles a changing climate, nuclear power is poised to provide the next wave of clean, affordable, safe and reliable power,” he told a packed room.

The Ottawa conference was the largest the industry has run with dozens of companies and more than 900 people in attendance. Provincial cabinet ministers from Saskatchewan and Ontario were also there. Those two provinces, along with New Brunswick, signed a memorandum in December as part of a premiers' nuclear initiative to work together on small modular reactor technology.

People need to know that it’s safe

Small modular reactors are units that produce less power than large generating stations, but can be constructed easier and are expected to be safer to operate. Canadian firms have about a dozen of the proposed reactors working their way through the regulatory process, with New Brunswick's SMR plans drawing scrutiny.

The smaller reactors could be used in groups to replace large units, but the industry also hopes to use them in rural or isolated communities, mines or even oilsands projects, potentially replacing the diesel power generators some remote communities use.

The Canadian government issued a road map to support the industry in 2018 and O’Regan committed Thursday to putting some teeth on that proposal later this year, as provinces like Ontario explore new large-scale nuclear plants to meet demand, with specific steps the government will take.

“We have been working so hard to support this industry. We are placing nuclear energy front and centre, something that has never been done before.”

O’Regan said the government’s role is a clear, streamlined regulatory system that will promote the industry, but also help the Canadian public to trust the reactors will be safe.

“People need to know that it’s safe. They need to know that it’s regulated. They need to know that it’s safe for them,” he said.

The Liberals promised during the campaign that they would gradually reduce Canada’s carbon emissions even after hitting the targets in the Paris Agreement by 2030. By 2050, Prime Minister Justin Trudeau said he expects Canada to be carbon neutral, mindful of lessons from Europe's power crisis on reliability.

The government hasn’t outlined how it will achieve that goal. O’Regan said more detail is coming, but it’s clear that nuclear is going to have to play a major part, echoing the UK’s green industrial revolution approach to reactor deployment.

“I have not seen a credible plan for net zero without nuclear as part of the mix. I don’t think we are going to be relying on any one technology. I think it’s going to be a whole host of things.”

O’Regan said large investors are looking for countries that are on the path to net zero.

“Everybody has their shirt sleeves rolled up and we know we need to work on this, not only do we have to work on this for the urgency of the planet, but we have to work on it for Canadian jobs.”

He added, “We must focus on those areas where Canada can and should lead, like nuclear.”

Canadians are ready to take a fresh look at nuclear

John Gorman, president of the Canadian Nuclear Association, said he was thrilled with O’Regan’s comments.

“I took the minister’s remarks this morning as being perhaps the strongest language of support for the nuclear industry in a number of years.”

Gorman said the industry is in strong shape and is working with utility companies such as Ontario Power Generation and regulators to move projects forward.

“It’s this amazing collaboration and coordination that is enabling us to beat others to the roll out of these small modular reactors,” he said.

He said provinces that might not have looked at nuclear before now have an incentive to do it, because of climate change. A former solar industry executive, Gorman said solar and wind power are important, as Ontario plans to seek new wind and solar power to ease supply pressures, but they won’t be able to keep up with rising power demands.

“Globally we are seeing increased recognition that climate change is real and that it’s a crisis, we are also seeing recognition that we are not making as much progress on decarbonizing our electricity system as we thought,” he said. “Canadians are ready to take a fresh look at nuclear and see the real facts.”

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California fossil fuel grid reliability plan addresses heat wave demand, rolling blackouts, and grid stability by temporarily procuring gas generation while accelerating renewables, storage, and transmission to meet clean energy and carbon-neutral targets by 2045.

Key Points

A stop-gap policy to prevent blackouts by buying fossil power while fast-tracking renewables, storage, and grid upgrades.

✅ Temporary procurement of gas to avoid rolling blackouts

✅ Accelerates renewables, storage, transmission permitting

✅ Aims for carbon neutrality by 2045 without new gas plants

California wants to quit fossil fuels. Just not yet Faced with a fragile electrical grid and the prospect of summertime blackouts, the state agreed to put aside hundreds of millions of dollars to buy power from fossil fuel plants that are scheduled to shut down as soon as next year.

That has prompted a backlash from environmental groups and lawmakers who say Democratic Gov. Gavin Newsom’s approach could end up extending the life of gas plants that have been on-track to close for more than a decade and could threaten the state’s goal to be carbon neutral by 2045.

“The emphasis that the governor has been making is ‘We’re going to be Climate Leaders; we’re going to do 100 percent clean energy; we’re going to lead the nation and the world,’” said V. John White, executive director of the Sacramento-based Center for Energy Efficiency and Renewable Technologies, a non-profit group of environmental advocates and clean energy companies. “Yet, at least a part of this plan means going the opposite direction.”

That plan was a last-minute addition to the state’s energy budget, which lawmakers in the Democratic-controlled Legislature reluctantly passed. Backers say it’s necessary to avoid the rolling blackouts like the state experienced during a heat wave in 2020. Critics see a muddled strategy on energy, and not what they expected from a nationally ambitious governor who has made climate action a centerpiece of his agenda.

The legislation, which some Democrats labeled as “lousy” and “crappy,” reflects the reality of climate change. Heat waves are already straining power capacity, and the transition to cleaner energy isn’t coming fast enough to meet immediate needs in the nation’s most populous state.

Officials have warned that outages would be possible this summer, as the grid faces heat wave tests again, with as many as 3.75 million California homes losing power in a worst-case scenario of a West-wide heat wave and insufficient electrical supplies, particularly in the evenings.

It’s also an acknowledgment of the political reality that blackout politics are hazardous to elected officials, even in a state dominated by one party.

Newsom emphasized that the money to prop up the power grid, part of a larger $4.3 billion energy spending package, is meant as a stop-gap measure. The bill allows the Department of Water Resources to spend $2.2 billion on “new emergency and temporary generators, new storage systems, clean generation projects, and funding on extension of existing generation operations, if any occur,” the governor said in a statement after signing the bill.

“Action is needed now to maintain reliable energy service as the State accelerates the transition to clean energy,” Newsom said.

Following the signing, the governor called for the state California Air Resources Board to add a set of ambitious goals to its 2022 Scoping Plan, which lays out California’s path for reducing carbon emissions.

Among Newsom’s requested changes is a move away from fossil fuels, asking state agencies to prepare for an energy transition that avoids the need for new natural gas plants.

Alex Stack, a spokesman for the governor, said in a statement that California has been a global leader in reducing pollution and exporting energy policies across Western states, and pointed to Newsom’s recent letter to the Air Resources Board as well as one sent to President Joe Biden outlining how states can work with the federal government to combat climate change.

“California took action to streamline permitting for clean energy projects to accelerate the build out of clean energy that is needed to meet our climate goals and help maintain reliability in the face of extreme heat, wildfires, and drought,” Stack said.

But the prospect of using state money on fossil fuel power, even in the short term, has raised ire among the state’s many environmental advocacy groups, and raised questions about whether California will be able to achieve its goals.

“What is so frustrating about an energy bill like this is that we are at crunch time to meet these goals,” said Mary Creasman, CEO of California Environmental Voters. “And we’re investing a scale of funding into things that exacerbate those goals.”
 
Emmanuelle Chriqui and Mary Creasman speak during the 2021 Environmental Media Association IMPACT Summit at Pendry West Hollywood on September 2, 2021 in West Hollywood, California. | Jesse Grant/Getty Images for Environmental Media Association

With climate change-induced drought and high temperatures continuing to ravage the West, California anticipates the demand on the grid will only continue to grow. Despite more than a decade of bold posturing and efforts to transition to solar, wind and hydropower, the state worries it doesn’t have enough renewable energy sources on hand to keep the power on in an emergency right now, amid a looming shortage that will test reliability.

The specter of power outages poses a hazard to Newsom, and Democrats in general, especially ahead of November. While the governor is widely expected to sail to reelection, rolling blackouts are a serious political liability — in 2003, they were the catalyst for recalling Democratic Gov. Gray Davis. A lack of power isn’t just about people sweating in the dark, said Steven Maviglio, a longtime Democratic consultant who served as communications director for Davis, it can affect businesses, travel and have an outsized impact on the economy.

It behooves any state official to keep the power on, but, unlike Davis, Newsom is under serious pressure to make sure the state also adheres to its climate goals.

“Gavin Newsom’s brand is based on climate change and clean air, so it’s a little more difficult for him to say ‘well that’s not as important as keeping the power on,’” Maviglio said.

The same bill effectively ends local government control over those projects, for the time being. It hopes to speed up the state’s production of renewable energy sources by giving exclusive authority over the siting of those projects to a single state agency for the next seven years.

Environmental advocates say the state is now scrambling to address an issue they’ve long known was coming. In 2010, California officials set a schedule to retire a number of coastal gas plants that rely on what’s known as once-through cooling systems, which are damaging to the environment, especially marine life, even as regulators weigh more power plants to maintain reliability today. Many of those plants have been retired since 2010, but others have received extensions.

The remaining plants have various deadlines for when they must cease operations, with the soonest being the end of 2023.

Also at issue is the embattled Diablo Canyon nuclear power plant, California’s largest electricity source. The Pacific Gas & Electric-owned plant is scheduled to close in 2025, but the strain on the grid has officials considering the possibility of seeking an extension. Newsom said earlier this spring he would be open to extending the life of the plant. Doing so would also require federal approval.

Al Muratsuchi stands and talks into a microphone with a mask on. 
Assemblyman Al Muratsuchi speaks during an Assembly session in Sacramento, Calif., on Jan. 31, 2022. | Rich Pedroncelli/AP Photo

The International Brotherhood of Electrical Workers 1245, a labor union, sees the energy package as a way to preserve Diablo Canyon, and jobs at the plant.

“The value to 1245 PG&E members at Diablo Canyon is clear — funding to keep the plant open,” the union said of the bill.

Assemblymember Al Muratsuchi (D-Los Angeles) criticized the bill as “crappy” when it came to the floor in late June, describing it as “a rushed, unvetted and fossil-fuel-heavy response” to the state’s need to bolster the grid.

“The state has had over 12 years to procure and bring online renewable energy generation to replace these once through cooling gas power plants,” Muratsuchi said. “Yet, the state has reneged on its promise to shut down these plants, not once, but twice already.”

Not all details of the state’s energy budget are final. Lawmakers still have $3.8 billion to allocate when they return on Aug. 1 for the final stretch of the year.

Creasman, at California Environmental Voters, said she wants lawmakers to set specific guidelines for how and where it will spend the $2.2 billion when they return in August to dole out the remaining money in the budget. Newsom and legislators also need to ensure that this is the last time California has to spend money on fossil fuel, she said.

“Californians deserve to see what the plan is to make sure we’re not in this position again of having to choose between making climate impacts worse or keeping our lights on,” Creasman said. “That’s a false choice.”

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Newfoundland and Labrador Energy Efficiency faces low rankings yet signs of progress: heat pumps, EV charging networks, stricter building codes, electrification to tap Muskrat Falls power and cut greenhouse gas emissions and energy poverty.

Key Points

Policies and programs improving N.L.'s energy use via electrification, EVs, heat pumps, and stronger building codes.

✅ Ranks last provincially but showing policy momentum

✅ Heat pump grants and EV charging network underway

✅ Stronger building codes and electrification can cut emissions

Ah, another day, another depressing study that places Newfoundland and Labrador as lagging behind the rest of Canada.

We've been in this place before — least-fit kids, lowest birthrate — and now we can add a new dubious distinction to the pile: a ranking of the provinces according to energy efficiency placed Newfoundland and Labrador last.

Efficiency Canada released its first-ever provincial scorecard Nov. 20, comparing energy efficiency policies among the provinces. With energy efficiency a key part of reducing greenhouse gas emissions, Newfoundland and Labrador sat in 10th place, noted for its lack of policies on everything from promoting EV uptake in Atlantic Canada to improving efficient construction codes.

But before you click away to a happier story (about, say, a feline Instagram superstar) one of the scorecard's authors says there's a silver lining to the statistics.

"It's not that Newfoundland and Labrador is doing anything badly; it's just that it could do more," said Brendan Haley, the policy director at Efficiency Canada, a new think tank based at Carleton University.

"There's just a general lack of attention to implementing efficiency policies relative to other jurisdictions, including New Brunswick's EV rebate programs on transportation."

Looking at the scorecard and comparing N.L. with British Columbia, which snagged the No. 1 spot, isn't a great look. B.C. scored 56 points out of a possible 100, while N.L. got just 15.

Haley pointed out that B.C.'s provincial government is charting progress toward 2032, when all new builds will have to be net-zero energy ready; that is, buildings that can produce as much clean energy as they consume.  

While it might not be feasible to emulate that to a T here, Haley said the province could be mandating better energy efficiency standards for new, large building projects, and, at the same time, promote electrification of such projects as a way to soak up some of that surplus Muskrat Falls electricity.

Staring down Muskrat's 'extraordinary' pressure on N.L. electricity rates

It's impossible to talk about energy efficiency in N.L. without considering that dam dilemma. As Muskrat Falls comes online, likely at the end of 2020, customer power rates are set to rise in order to pay for it, and the province is still trying to figure out the headache that is rate mitigation.

"There is a strategic choice to be made in Newfoundland and Labrador," Haley told CBC Radio's On The Go.

While having more customers using Muskrat Falls power can help with rate mitigation, including through initiatives like N.L.'s EV push to grow demand, Haley noted simply using its excess electricity for the sake of it isn't a great goal.

"That should not be an excuse, I think, to almost have a policy of wasting energy on purpose, or saying that we don't need programs that help save electricity anymore," he said.

Energy poverty
Lots of N.L. homeowners are currently feeling a chill from the spectre of rising electricity rates.

Of course, that draft could be coming from a poorly insulated and heated house, as Efficiency Canada noted 38 per cent of all households in N.L. live in what it calls "energy poverty," where they spend more than six per cent of their after-tax income on energy — that's the second highest such rate in the country.

That poverty speaks for a need for N.L.to boost efficiency incentives for vulnerable populations, although Haley noted the government is making progress. The province recently expanded its home energy savings program, doubling in the last budget year to $2 million, which gives grants to low income households for upgrades like insulation.

Can you guess what products are selling like hotcakes as Muskrat Falls looms? Heat pumps

And since Efficiency Canada compiled its scorecard, the province has introduced a $1-million heat pump program, in which 1,000 homeowners could receive $1,000 toward the purchase of a heat pump. 

That program began accepting applications Oct. 15, and one month in, has had 682 people apply, according to the Department of Municipal Affairs and Environment, along with thousands of inquiries.

Heat pump popularity
Even without that program, heat pump sales have skyrocketed in the province since 2017. That popularity doesn't come as much of a surprise to Darren Brake, the president of KSAB Construction in Corner Brook.

With more than two decades in the home building business, he's been seeing consumer demand for home energy efficiency rise to the point where a year ago, his company transitioned into only building third-party certified energy efficient homes.

"Everybody's really concerned about the escalating power costs and energy costs, I assume because of Muskrat Falls," he said.

"It's evolving now, as we speak. Everybody is all about that monthly payment."

Brake uses spray foam installation in every house he builds, to seal up any potential leaks. Without sealing the building envelope, he says, a heat pump is far less efficient. (Lindsay Bird/CBC)
And in the weakest housing market in the province in half a century, Brake has been steadily moving his, building and selling seven in the last year.

Brake's houses include heat pumps, but he said the real savings come from their heavily insulated walls, roof and floors. Homeowners looking to install a heat pump in their leaky old house, he said, won't see lower power bills in quite the same way.

"They are energy efficient, but it's more about the building envelope to make a home efficient and easy to heat. You can put a heat pump in an older home that leaks a lot of air, and you won't get the same results," he said.

Charging network coming
The other big piece to the efficiency puzzle — in the scorecard's eyes — is electric vehicles. Those could, again, use some of that Muskrat Falls energy, as well as curtail gas guzzling, but Efficiency Canada pointed to a lack of policies and incentives surrounding electrifying transportation, such as Nova Scotia's vehicle-to-grid pilot that illustrates innovation elsewhere.

Unlike Quebec or B.C., the province doesn't offer a rebate for buying EVs, even as N.W.T. encourages EVs through targeted measures, and while electric vehicles got loud applause at the House of Assembly last week, it was absent of any policy or announcement beyond the province unveiling a EV licence plate design to be used in the near future.

Electric-vehicle charging network planned for N.L. in 2020

But since the scorecard was tallied, NL Hydro has unveiled plans for a Level 3 charging network for EVs across the island, dependent on funding, with N.L.'s first fast-charging network seen as just the beginning for local drivers.

NL Hydro says while its request for proposals for an island-wide charging network closed earlier in November, there is no progress update yet, even as N.B.'s fast-charging rollout advances along the Trans-Canada. (Credit: iStock/Getty Images)
That cash appears to still be in limbo, as "we are still progressing through the funding process," said an NL Hydro spokesperson in an email, with no "additional details to release at this time."

Still, the promise of a charging network — plus the swift uptake on the heat pump program — could boost N.L.'s energy efficiency scorecard next time it's tallied, said Haley.

"It is encouraging to see the province moving forward on smart and efficient electrification," he said.

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ISEM Price Volatility reflects Ireland-Northern Ireland grid balancing pressures, driven by dispatchable power shortages, day-ahead market dynamics, renewable shortfalls, and interconnector constraints, affecting intraday trading, operational reserves, and cross-border electricity flows.

Key Points

ISEM price volatility is Irish power price swings from grid balancing stress and limited dispatchable capacity.

✅ One-off spike linked to plant outage and low renewables

✅ Day-ahead market settling; intraday trading integration pending

✅ Interconnectors and reserves vital to manage adequacy

Irish grid-balancing prices soared to €3,774 ($4,284) per megawatt-hour last month amid growing concerns over dispatchable power capacity across Europe.

The price spike, triggered by an alert regarding generation losses, came only four months after Ireland and Northern Ireland launched an Integrated Single Electricity Market (ISEM) designed to make trading more competitive and improve power distribution across the island.

Evie Doherty, senior consultant for Ireland at Cornwall Insight, a U.K.-based energy consultancy, said significant price volatility was to be expected while ISEM is still settling down, aligning with broader 2019 grid edge trends seen across markets.

When the U.K. introduced a single market for Great Britain, called British Electricity Trading and Transmission Arrangements, in 2005, it took at least six months for volatility to subside, Doherty said.

In the case of ISEM, “it will take more time to ascertain the exact drivers behind the high prices,” she said. “We are being told that the day-ahead market is functioning as expected, but it will take time to really be able to draw conclusions on efficiency.”

Ireland and Northern Ireland have been operating with a single market “very successfully” since 2007, said Doherty. Although each jurisdiction has its own regulatory authority, they make joint decisions regarding the single market.

ISEM, launched in October 2018, was designed to help include Ireland and Northern Ireland day-ahead electricity prices in a market pricing system called the European Union Pan-European Hybrid Electricity Market Integration Algorithm.

In time, ISEM should also allow the Irish grids to participate in European intraday markets, and recent examples like Ukraine's grid connection underline the pace of integration efforts across Europe. At present, they are only able to do so with Great Britain. “The idea was to...integrate energy use and create more efficient flows between jurisdictions,” Doherty said.

EirGrid, the Irish transmission system operator, has reported that flows on its interconnector with Northern Ireland are more efficient than before, she said.

The price spike happened when the System Operator for Northern Ireland issued an alert for an unplanned plant outage at a time of low renewable output and constraints on the north-south tie-line with Ireland, according to a Cornwall Insight analysis.

Not an isolated event

Although it appears to have been a one-off event, there are increasing worries that a shortage of dispatchable power could lead to similar situations elsewhere across Europe, as seen in Nordic grid constraints recently.

Last month, newspaper Frankfurter Allgemeine Zeitung (FAZ) reported that German industrial concerns had been forced to curtail more than a gigawatt of power consumption to maintain operational reserves on the grid in December, after renewable production fell short of expectations and harsh weather impacts strained systems elsewhere.

Paul-Frederik Bach, a Danish energy consultant, has collected data showing that this was not an isolated incident. The FAZ report said German aluminum smelters had been forced to cut back on energy use 78 times in 2018, he noted.

Energy availability was also a concern last year in Belgium, where six out of seven nuclear reactors had been closed for maintenance. The closures forced Belgium to import 23 percent of its electricity from neighboring countries, Bach reported.

In a separate note, Bach revealed that 11 European countries that were net importers of energy had boosted their imports by 26 percent between 2017 and 2018. It is important to note that electricity imports do not necessarily imply a shortage of power, he stated.

However, it is also true that many European grid operators are girding themselves for a future in which dispatchable power is scarcer than today.

EirGrid, for example, expects dispatchable generation and interconnection capacity to drop from 10.6 gigawatts in 2018 to 9 gigawatts in 2027.

The Swedish transmission system operator Svenska Kraftnät, meanwhile, is forecasting winter peak power deficits could rise from 400 megawatts currently to 2.5 gigawatts in 2020-21.

Research conducted by the European Network of Transmission System Operators for Electricity, suggests power adequacy will fall across most of Europe up to 2025, although perhaps not to a critical degree.

The continent’s ability to deal with the problem will be helped by having more efficient trading systems, Bach told GTM. That means developments such as ISEM could be a step in the right direction, despite initial price volatility.

In the long run, however, Europe will need to make sure market improvements are accompanied by investments in HVDC technology and interconnectors and reserve capacity. “Somewhere there must be a production of electricity, even when there is no wind,” said Bach. 

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Electric Vehicle Grid Integration aligns EV charging with grid capacity using smart charging, time-of-use rates, V2G, and demand response to reduce peak load, enable renewable energy, and optimize infrastructure planning.

Key Points

Aligning EV charging with grid needs via smart charging, TOU pricing, and V2G to balance load and support renewables.

✅ Time-of-use rates shift charging to off-peak hours

✅ Smart charging responds to real-time grid signals

✅ V2G turns fleets into distributed energy storage

When Seattle City Light unveiled five new electric vehicle charging stations last month in an industrial neighborhood south of downtown, the electric utility wasn't just offering a new spot for drivers to fuel up. It also was creating a way for the service to figure out how much more power it might need as electric vehicles catch on.

Seattle aims to have nearly a third of its residents driving electric vehicles by 2030. Washington state is No. 3 in the nation in per capita adoption of plug-in cars, behind California and Hawaii. But as Washington and other states urge their residents to buy electric vehicles — a crucial component of efforts to reduce carbon emissions — they also need to make sure the electric grid can handle it amid an accelerating EV boom nationwide.

The average electric vehicle requires 30 kilowatt hours to travel 100 miles — the same amount of electricity an average American home uses each day to run appliances, computers, lights and heating and air conditioning.

An Energy Department study found that increased electrification across all sectors of the economy could boost national consumption by as much as 38 percent by 2050, in large part because of electric vehicles. The environmental benefit of electric cars depends on the electricity being generated by renewables.

So far, states predict they will be able to sufficiently boost power production. But whether electric vehicles will become an asset or a liability to the grid largely depends on when drivers charge their cars.

Electricity demand fluctuates throughout the day; demand is higher during daytime hours, peaking in the early evening. If many people buy electric vehicles and mostly try to charge right when they get home from work — as many now do — the system could get overloaded or force utilities to deliver more electricity than they are capable of producing.

In California, for example, the worry is not so much with the state’s overall power capacity, but rather with the ability to quickly ramp up production and maintain grid stability when demand is high, said Sandy Louey, media relations manager for the California Energy Commission, in an email. About 150,000 electric vehicles were sold in California in 2018 — 8 percent of all state car sales.

The state projects that electric vehicles will consume 5.4 percent of the state’s electricity, or 17,000 gigawatt hours, by 2030.

Responding to the growth in electric vehicles will present unique challenges for each state. A team of researchers from the University of Texas at Austin estimated the amount of electricity that would be required if every car on the road transitioned to electric. Wyoming, for instance, would need to nudge up its electricity production only 17 percent, while Maine would have to produce 55 percent more.

Efficiency Maine, a state trust that oversees energy efficiency and greenhouse gas reduction programs, offers rebates for the purchase of electric vehicles, part of state efforts to incentivize growth.

“We’re certainly mindful that if those projections are right, then there will need to be more supply,” said Michael Stoddard, the program’s executive director. “But it’s going to unfold over a period of the next 20 years. If we put our minds to it and plan for it, then we should be able to do it.”

A November report sponsored by the Energy Department found that there has been almost no increase in electricity demand nationwide over the past 10 years, while capacity has grown an average of 12 gigawatts per year (1 GW can power more than a half-million homes). That means energy production could climb at a similar rate and still meet even the most aggressive increase in electric vehicles, with proper planning.

Charging during off-peak hours would allow not only many electric vehicles to be added to the roads but also utilities to get more use out of power plants that run only during the limited peak times through improved grid coordination and flexible demand.

Seattle City Light and others are looking at various ways to promote charging during ideal times. One method is time-of-day rates. For the Seattle chargers unveiled last month, users will pay 31 cents per kilowatt hour during peak daytime hours and 17 cents during off-peak hours. The utility will monitor use at its charging stations to see how effective the rates are at shifting charging to more favorable times.

The utility also is working on a pilot program to study charging behavior at home. And it is partnering with customers such as King County Metro that are electrifying large vehicle fleets, including growing electric truck fleets that will demand significant power, to make sure they have both the infrastructure and charging patterns to integrate smoothly.

“Traditionally, our utility approach is to meet the load demand,” said Emeka Anyanwu, energy innovation and resources officer for Seattle City Light.

Instead, he said, the utility is working with customers to see whether they can use existing assets without the need for additional investment.

Numerous analysts say that approach is crucial.

“Even if there’s an overall increase in consumption, it really matters when that occurs,” said Sally Talberg, head of the Michigan Public Service Commission, which oversees the state’s utilities. “The encouragement of off-peak charging and other technology solutions that could come to bear could offset any negative impact.”

One of those solutions is smart charging, a system in which vehicles are plugged in but don’t charge until they receive a signal from the grid that demand has tapered off a sufficient amount. This is often paired with a lower rate for drivers who use it. Several smart-charging pilot programs are being conducted by utilities, although they have not yet been phased in widely, amid ongoing debates over charging control among manufacturers and utilities.

In many places, the increased electricity demand from electric vehicles is seen as a benefit to utilities and rate payers. In the Northwest, electricity consumption has remained relatively stagnant since 2000, despite robust population growth and development. That’s because increasing urbanization and building efficiency have driven down electricity needs.

Electric vehicles could help push electricity consumption closer to utilities’ capacity for production. That would bring in revenue for the providers, which would help defray the costs for maintaining that capacity, lowering rates for all customers.

“Having EV loads is welcome, because it’s environmentally cleaner and helps sustain revenues for utilities,” said Massoud Jourabchi, manager of economic analysis for the Northwest Power and Conservation Council, which develops power plans for the region.

Colorado also is working to promote electric cars, with the aim of putting 940,000 on the road by 2030. The state has adopted California’s zero-emission vehicles mandate, which requires automakers to reach certain market goals for their sales of cars that don’t burn fossil fuels, while extending tax credits for the purchase of such cars, investing in charging stations and electrifying state fleets.

Auto dealers have opposed the mandate, saying it infringes on consumer freedom.

“We think it should be a customer choice, a consumer choice and not a government mandate,” said Tim Jackson, president and chief executive of the Colorado Automobile Dealers Association.

Jackson also said that there’s not yet a strong consumer appetite for electric vehicles, meaning that manufacturers that fail to sell the mandated number of emission-free vehicles would be required to purchase credits, which he thinks would drive up the price of their other models.

Republicans in the state have registered similar concerns, saying electric vehicle adoption should take place based on market forces, not state intervention.

Many in the utility community are excited about the potential for electric cars to serve as mobile energy storage for the grid. Vehicle-to-grid technology, known as V2G, would allow cars charging during the day to take on surplus power from renewable energy sources.

Then, during peak demand times, electric vehicles would return some of that stored energy to the grid. As demand tapers off in the evening, the cars would be able to recharge.

In practice, V2G technology could be especially beneficial if used by heavy-duty fleets, such as school buses or utility vehicles. Those fleets would have substantial battery storage and long periods where they are idle, such as evenings and weekends — and even longer periods such as summer and the holiday season when school is out. The batteries on a bus, Jourabchi said, could store as much as 10 times the electricity needed to power a home for a day.

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Futaba Partial Reopening marks limited access to the Fukushima exclusion zone, highlighting radiation decontamination progress, the train station restart, and regional recovery ahead of the Tokyo Olympics after the 2011 nuclear disaster and evacuation.

Key Points

A lift of entry bans in Futaba, signaling Fukushima recovery, decontamination progress, and a train station restart.

✅ Unrestricted access to 2.4 km² around Futaba Station

✅ Symbolic step ahead of Tokyo Olympics torch relay

✅ Decommissioning and decontamination to span decades

Japan's government on Wednesday opened part of the last town that had been off-limits due to radiation since the Fukushima nuclear disaster nine years ago, in a symbolic move to show the region's recovery ahead of the Tokyo Olympics, even as grid blackout risks have drawn scrutiny nationwide.

The entire population of 7,000 was forced to evacuate Futaba after three reactors melted down due to damage at the town's nuclear plant caused by a magnitude 9. 0 quake and tsunami March 11, 2011.

The partial lifting of the entry ban comes weeks before the Olympic torch starts from another town in Fukushima, as new energy projects like a large hydrogen system move forward in the prefecture. The torch could also arrive in Futaba, about 4 kilometres (2.4 miles) from the wrecked nuclear plant.

Unrestricted access, however, is only being allowed to a 2.4 square-kilometre (less than 1 square-mile) area near the main Futaba train station, which will reopen later this month to reconnect it with the rest of the region for the first time since the accident. The vast majority of Futaba is restricted to those who get permission for a day visit.

The three reactor meltdowns at the town's Fukushima Dai-ichi nuclear power plant spewed massive amounts of radiation that contaminated the surrounding area and at its peak, forced more than 160,000 people to flee, even as regulators later granted TEPCO restart approval for a separate Niigata plant elsewhere in Japan.

The gate at a checkpoint was opened at midnight Tuesday, and Futaba officials placed a signboard at their new town office, at a time when the shutdown of Germany's last reactors has reshaped energy debates abroad.

“I'm overwhelmed with emotion as we finally bring part of our town operations back to our home town," said Futaba Mayor Shiro Izawa. “I pledge to steadily push forward our recovery and reconstruction."

Town officials say they hope to see Futaba’s former residents return, but prospects are grim because of lingering concern about radiation, and as Germany's nuclear exit underscores shifting policies abroad. Many residents also found new jobs and ties to communities after evacuating, and only about 10% say they plan to return.

Futaba's registered residents already has decreased by 1,000 from its pre-disaster population of 7,000. Many evacuees ended up in Kazo City, north of Tokyo, after long bus trips, various stopovers and stays in shelters at an athletic arena and an abandoned high school. The town's government reopened in a makeshift office in another Fukushima town of Iwaki, while abroad projects like the Bruce reactor refurbishment illustrate long-term nuclear maintenance efforts.

Even after radiation levels declined to safe levels, the region's farming and fishing are hurt by lingering concerns among consumers and retailers. The nuclear plant is being decommission in a process that will take decades, with spent fuel removal delays extending timelines, and it is building temporary storage for massive amounts of debris and soil from ongoing decontamination efforts.

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