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NB Power copper thefts highlight risks at high-voltage substations, with vandalism, fatalities, infrastructure damage, ratepayer costs, and law enforcement alerts tied to metal prices, stolen electricity, and safety concerns across New Brunswick and Nova Scotia.

Key Points

Substation metal thefts causing fatalities, outages, safety risks, and higher costs that impact NB ratepayers.

✅ Spike aligns with copper price near $3 per pound

✅ Fatal break-ins at high-voltage facilities in Bathurst

✅ Repairs, delays, and safety risks for crews, customers

New Brunswick's power utility is urging people to stay away from its substations, saying the valuable copper they contain is proving hard to resist for thieves.

NB Power has seen almost as many incidents of theft and vandalism to its property in April and May of this year, than in all of last year.

In the 2018-2019 fiscal year, the utility recorded 16 cases of theft and/or vandalism.

In April and May, there have already been 13 cases.

One of those was a fatal incident in Bathurst. On April 13, a 41-year-old man was found unresponsive and later died, after breaking into a substation. It was the second fatality linked to a break-in at an NB Power facility in 10 years.

The investigation is still ongoing, but NB Power believes the man was trying to steal copper.

The power utility has been ramping up its efforts -- finding alternate ways to secure its properties, and educate the public -- on the dangers of copper theft, as utilities work to adapt to climate change that can exacerbate severe weather.

“We really, really, really want to stress that if you’re hitting the wrong wire, cutting the wrong wire, breaking in to or cutting fences, a lot of very bad things can happen,” said NB Power spokesperson Marc Belliveau.

In the 2017-2018 fiscal year, there were 24 recorded cases of theft and/or vandalism.

It also comes at a financial cost for NB Power, and ratepayers -- on average, $330,000 a year. About two-thirds of that is copper. The rest is vehicle break-ins or stolen electricity.

“We’ve done analysis,” Belliveau said. “Often the number of break-ins correspond with the price spiking in copper. So, right now, copper’s about $3 a pound. If it was half of that, there might be half as many incidents.”

New Brunswick Public Safety Minister Carl Urquhart says he knows the utility and police are working to dissuade people from the dangers of the theft, and notes that debates around Site C dam stability issues reflect broader infrastructure safety concerns.

“We all know of incident after incident of major injuries and death caused by, simply by, copper,” he said.

Last November, a Dawson Settlement substation was targeted during a major, storm-related power outage in the province.

It meant NB Power had to divert crews to fix and secure the substation, delaying restoration times for some residents and underscoring efforts to improve local reliability across the grid.

Belliveau says that’s “most frustrating.”

“We’re really trying to take a more proactive approach. And certainly, we encourage people that if you know somebody who’s thinking of doing something like that, to really try and talk them out of it because it’s unbelievably dangerous to break in to a substation,” he said.

Nova Scotia Power, connected through the Maritime Link, was not able to provide details on thefts at their substations, but spokesman David Rodenhiser said "the value of the stolen copper is minor in comparison to the risk that’s created when thieves break into our high-voltage electrical substations."

It's not just risky for the people breaking in, and public opposition to projects like Site C underscores broader community safety concerns.

"It also puts the safety of the workers who maintain our substations at risk, because when thieves steal copper, the protective safety devices in the substations don’t work properly," Rodenhiser said.

Additionally, in Nova Scotia, projects like the Maritime Link have advanced regional transmission, and Nova Scotia Power’s copper components have identifying markers, which make that copper difficult to fence. Anyone who buys or sells stolen propery is at risk of criminal charges.

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Texas Power Grid Reliability faces record peak demand as ERCOT balances renewable energy, wind and solar variability, gas-fired generation, demand response, and transmission limits to prevent blackouts during heat waves and extreme weather.

Key Points

Texas Power Grid Reliability is ERCOT's capacity to meet peak demand with diverse resources while limiting outages.

✅ Record heat drives peak demand across ERCOT.

✅ Variable wind/solar need firm, flexible capacity.

✅ Demand response and reserves reduce blackout risk.

The electric power grid in Texas, which collapsed dramatically during the 2021 winter storm across the state, is being tested again as the state suffers unusually hot summer weather. Demand for electricity has reached new records at a time of rapid change in the mix of power sources as wind and solar ramp up. That’s feeding a debate about the dependability of the state’s power. 

1. Why is the Texas grid under threat again? 

Already the biggest power user in the nation, electricity use in the second most-populous state surged to record levels during heat waves this summer. The jump in demand comes as the state becomes more dependent on intermittent renewable power sources, raising concerns among some critics that more reliance on wind and solar will leave the grid more vulnerable to disruption. Green sources will produce almost 40% of the power in Texas this year, US Energy Information Administration data show. While that trails California’s 52%, Texas is a bigger market. It’s already No. 1 in wind, making it the largest clean energy market in the US. 

2. How is Texas unique? 

The spirit of defiance of the Lone Star State extends to its power grid as well. The Electric Reliability Council of Texas, or Ercot as the grid operator is known, serves about 90% of the state’s electricity needs and has very few high-voltage transmission lines connecting to nearby grids. It’s a deliberate move to avoid federal oversight of the power market. That means Texas has to be mainly self-reliant and cannot depend on neighbors during extreme conditions. That vulnerability is a dramatic twist for a state that’s also the energy capital of the US, thanks to vast oil and natural gas producing fields. Favorable regulations are also driving a wind and solar boom in Texas. 

3. Why the worry? 

The summer of 2023 will mark the first time all of the state’s needs cannot be met by traditional power plants, like nuclear, coal and gas. A sign of potential trouble came on June 20 when state officials urged residents to conserve power because of low supplies from wind farms and unexpected closures of fossil-fuel generators amid supply-chain constraints that limited availability. As of late July, the grid was holding up, thanks to the help of renewable sources. Solar generation has been coming in close to expected summer capacity, or exceeding it on most days. This has helped offset the hours in the middle of the day when wind speeds died down in West Texas. 

4. Why didn’t the grid’s problems get fixed? 

There is no easy fix. The Texas system allows the price of electricity to swing to match supply and demand. That means high prices — and high profits — drive the development of new power plants. At times spot power prices have been as low as $20-$50 a megawatt-hour versus more than $4,000 during periods of stress. The limitation of this pricing structure was laid bare by the 2021 winter blackouts. Since then, state lawmakers have passed market reforms that require weatherization of critical infrastructure and changed rules to put more money in the pockets of the owners of power generation.  

5. What’s the big challenge? 

There’s a real clash going on over what the grid of the future should look like in Texas and across the country, especially as severe heat raises blackout risks nationally. The challenge is to make sure nuclear and fossil fuel plants that are needed right now don’t retire too early and still allow newer, cleaner technologies to flourish. Some conservative Republicans have blamed renewable energy for destabilizing the grid and have pushed for more fossil-fuel powered generators. Lawmakers passed a controversial $10 billion program providing low-interest loans and grants to build new gas-fired plants using taxpayer money, but Texans ultimately have to vote on the subsidy. 

6. Why do improvements take so long? 

Figuring out how to keep the lights on without overburdening consumers is becoming a greater challenge amid more extreme weather fueled by climate change. As such, changing the rules is often a hotly contested process pitting utilities, generators, manufacturers, electricity retailers and other groups against one another. The process became more politicized after the storm in 2021 with Republican Gov. Greg Abbott and lawmakers ordering Ercot to make changes. Building more transmission lines and connecting to other states can help, but such projects are typically tied up for years in red tape.

7. What can be done? 

The price cap for electricity was cut from $9,000/MWh to $5,000 to help avoid the punitive costs seen in the 2021 storm, though prices are allowed to spike more easily. Ercot is also contracting for more reserves to be online to help avoid supply shortfalls and improve reliability for customers, which added $1.7 billion in consumer costs alone last year. Another rule helps some gas generators pay for their fuel costs, while a more recent reform put in price floors when reserves fall to certain levels. Many power experts say that the easiest solution is to pay people to reduce their energy consumption during times of grid stress through so-called demand response programs. Factories, Bitcoin miners and other large users are already compensated to conserve during tight grid conditions.

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Canada Net-Zero Grid Lessons highlight Europe's energy transition risks: Germany's power prices, wind and solar variability, nuclear phaseout, grid reliability, storage, market design, policy reforms, and distributed energy resources for resilient decarbonization.

Key Points

Lessons stress an all-of-the-above mix, robust market design, storage, and nuclear to ensure reliability, affordability.

✅ Diversify: nuclear, hydro, wind, solar, storage for reliability.

✅ Reform markets and grid planning for integration and flexibility.

✅ Build fast: streamline permitting, invest in transmission and DERs.

Europe is currently suffering the consequences of an uncoordinated rush to carbon-free electricity that experts warn could hit Canada as well unless urgent action is taken.

Power prices in Germany, for example, hit a record 91 euros ($135 CAD) per megawatt-hour earlier this month. That is more than triple what electricity costs in Ontario, where greening the grid could require massive investment, even during periods of peak demand.

Experts blame the price spikes in large part on a chaotic transition to a specific set of renewable electricity sources - wind and solar - at the expense of other carbon-free supplies such as nuclear power. Germany, Europe’s largest economy, plans to close its last remaining nuclear power plant next year despite warnings that renewables are not being added to the German grid quickly enough to replace that lost supply.

As Canada prepares to transition its own electricity grid to 100 per cent net-zero supplies by 2035, with provinces like Ontario planning new wind and solar procurement, experts say the European power crisis offers lessons this country must heed in order to avoid a similar fate.

'A CAUTIONARY TALE'
“Some countries have rushed their transition without thinking about what people need and when they need it,” said Chris Bentley, managing director of Ryerson University’s Legal Innovation Zone who also served as Ontario’s Minister of Energy from 2011 to 2013, in an interview. “Germany has experienced a little bit of this issue recently when the wind wasn’t blowing.”

Wind power usually provides between 20 and 30 per cent of Germany’s electricity needs, but the below-average breeze across much of continental Europe in recent months has pushed that figure down.

“There is a cautionary tale from the experience in Europe,” said Francis Bradley, chief executive officer of the Canadian Electricity Association, in an interview. “There was also a cautionary tale from what took place this past winter in Texas,” he added, referring to widespread power failures in Texas spawned by a lack of backup power supplies during an unusually cold winter that led to many deaths.

The first lesson Canada must learn from those cautionary tales, Bradley said, “is the need to pursue an all-of-the-above approach.”

“It is absolutely essential that every opportunity and every potential technology for low-carbon or no-carbon electricity needs to be pursued and needs to be pursued to the fullest,” he said.

The more important lesson for Canada, according to Binnu Jeyakumar, is about the need for a more holistic, nuanced approach to our own net-zero transition.

“It is very easy to have runaway narratives that just pinpoint the blame on one or two issues, but the lesson here isn’t really about the reliability of renewables as there are failures that occur across all sources of electricity supply,” said Jeyakumar, director of clean energy for the Pembina Institute, in an interview. 

“The takeaway for us is that we need to get better at learning how to integrate an increasingly diverse electricity grid,” she said. “It is not necessarily the technologies themselves, it is about how we do grid planning, how are our markets structured and are we adapting them to the trends that are evolving in the electricity and energy sectors.”
 

'ABSOLUTELY ENORMOUS' CHALLENGE IS 'ALMOST MIND-BENDING'
Canada already gets the vast majority of its electricity from emission-free sources. Hydro provides roughly 60 per cent of our power, nuclear contributes another 15 per cent and renewables such as wind and solar contribute roughly seven per cent more, according to federal government data.

Tempting as it might be to view the remaining 18 per cent of Canadian electricity that is supplied by oil, natural gas and coal as a small enough proportion that it should be relatively easy to replace, with some analyses warning that scrapping coal abruptly can be costly for consumers, the reality is much more difficult.

“It is the law of diminishing returns or the 80-20 rule where the first 80 per cent is easy but the last 20 per cent is hard,” Bradley explained. “We already have an electricity sector that is 80 per cent GHG-free, so getting rid of that last 20 per cent is the really difficult part because the low-hanging fruit has already been picked.”

Key to successfully decarbonizing Canada’s power grid will be the recognition that electricity demand is constantly growing, a point reinforced by a recent power challenges report that underscores the scale. That means Canada needs to build out enough emission-free power sources to replace existing fossil fuel-based supplies while also ensuring adequate supplies for future demand.

“It is one thing to say that by 2035 we are going to have a decarbonized electricity system, but the challenge really is the amount of additional electricity that we are going to need between now and 2035,” said John Gorman, chief executive officer of the Canadian Nuclear Association, which has argued that nuclear is key to climate goals in Canada, and former CEO of the Canadian Solar Industries Association, in an interview. “It is absolutely enormous, I mean, it is almost mind-bending.”

Canada will need to triple the amount of electricity produced nationwide by 2050, according to a report from SNC-Lavalin published earlier this year, and provinces such as Ontario face a shortfall over the next few years, Gorman said. Gorman said that will require adding between five and seven gigawatts of new installed capacity to Canada’s electricity grid every year from 2021 through 2050 or more than twice the amount of new power supply Canada brings online annually right now.

For perspective, consider Ontario’s Bruce Power nuclear facility. It took 27 years to bring that plant to its current 6.4 gigawatt (GW) capacity, but meeting Canada’s decarbonization goals will require adding roughly the equivalent capacity of Bruce Power every year for the next three decades.

“The task of creating enough electricity in the coming years is truly enormous and governments have not really wrapped their heads around that yet,” Gorman said. “For those of us in the energy sector, it is the type of thing that can keep you up at night.”

GOVERNMENT POLICY 'HELD HOSTAGE' BY 'DINOSAURS'
The Pembina Institute’s Jeyakumar agreed “the last mile is often the most difficult” and will require “a concerted effort both at the federal level and the provincial level.”

Governments will “need to be able to support innovation and solutions such as non-wires alternatives,” she said. “Instead of building a massive new transmission line or beefing up an old one, you could put a storage facility at the end of an existing line. Distributed energy resources provide those kinds of non-wires alternatives and they are already cost-effective and competitive with oil and gas.”

For Glen Murray, who served as Ontario’s minister of infrastructure and transportation from early 2013 to mid-2014 before assuming the environment and climate change portfolio until his resignation in mid-2017, that is a key lesson governments have yet to learn.

“We are moving away from a centralized distribution model to distributed systems where individual buildings and homes and communities will supply their own electricity needs,” said Murray, who currently works for an urban planning software company in Winnipeg, in an interview. “Yet both the federal and provincial governments are assuming that we are going to continue to have large, centralized generation of power, but that is simply not going to be the case.”

“Government policy is not focused on driving that because they are held hostage by their own hydro utilities and the big gas companies,” Murray said. “They are controlling the agenda even though they are the dinosaurs.”

Referencing the SNC-Lavalin report, Gorman noted as many as 45 small, modular nuclear reactors as well as 20 conventional nuclear power plants will be required in the coming decades, with jurisdictions like Ontario exploring new large-scale nuclear as part of that mix: “And that is in the context of also maximizing all the other emission-free electricity sources we have available as well from wind to solar to hydro and marine renewables,” Gorman said, echoing the “all-of-the-above” mindset of the Canadian Electricity Association.

There are, however, “fundamental rules of the market and the regulatory system that make it an uneven playing field for these new technologies to compete,” said Jeyakumar, agreeing with Murray’s concerns. “These are all solvable problems but we need to work on them now.”
 

'2035 IS TOMORROW'
According to Bentley, the former Ontario energy minister-turned academic, “the government's role is to match the aspiration with the means to achieve that aspiration.”

“We have spent far more time as governments talking about the goals and the high-level promises [of a net-zero electricity grid by 2035] without spending as much time as we need to in order to recognize what a massive transformation this will mean,” Bentley said. “It is easy to talk about the end-goal, but how do you get there?”

The Canadian Electricity Assocation’s Bradley agreed “there are still a lot of outstanding questions about how we are going to turn those aspirations into actual policies. The 2035 goal is going to be very difficult to achieve in the absence of seeing exactly what the policies are that are going to move us in that direction.”

“It can take a decade to go through the processes of consultations and planning and then building and getting online,” Bradley said. “Particularly when you’re talking about big electricity projects, 2035 is tomorrow.”

Jeyakumar said “we cannot afford to wait any longer” for policies to be put in place as the decisions governments make today “will then lock us in for the next 30 or 40 years into specific technologies.”

“We need to consider it like saving for retirement,” said Gorman of the Canadian Nuclear Association. “Every year that you don’t contribute to your retirement savings just pushes your retirement one more year into the future.”

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Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

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Egypt Renewable Energy Expansion targets solar and wind power projects to diversify the energy mix, adding 6.6 GW by 2020 and reaching 8,200 MW, with UK cooperation, grid upgrades, and investment in the electricity sector.

Key Points

A plan to boost solar and wind by 6.6 GW by 2020, reaching 8,200 MW and diversifying Egypt's energy mix.

✅ Adds 6.6 GW by 2020; targets 8,200 MW total capacity

✅ Focus on solar, wind, grid upgrades, and investment

✅ UK-Egypt cooperation in electricity sector projects

Egypt is planning to expand into renewable energy projects in a bid to increase its contribution to the energy mix, in step with global records being set in renewables, and amid Saudi Arabia’s 60 GW drive in the region, the country’s minister of electricity and renewable energy Mohamed Shaker said.

Renewable power is expected to add 6.6 gigawatts (GW) by the end of 2020, a scale comparable to Saudi wind expansion underway, with plans to reach 8,200 megawatts (MW) after the completion of the renewable energy projects currently under consideration, reflecting gains seen since IRENA’s 2016 record year for renewables, Shaker added in a statement on Tuesday, even as regional challenges persist.

This came during the minister’s video-conference meeting with the British ambassador to Egypt Geoffrey Adams to explore the potential means for cooperation between the two countries in the electricity sector, including lessons from the UK project backlog now affecting investments and from Ireland’s green-electricity goals being pursued.

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PG&E Public Safety Power Shutoff reduces wildfire risk during extreme winds, triggering de-energization across the North Bay and Sierra Foothills under red flag warnings, with safety inspections and staged restoration to improve grid resilience.

Key Points

A utility protocol to de-energize lines during extreme fire weather, reducing ignition risks and improving grid safety.

✅ Triggered by red flag warnings, humidity, wind, terrain

✅ Temporary de-energization of transmission and distribution lines

✅ Inspections precede phased restoration to minimize wildfire risk

PG&E purposefully shut off electricity to nearly 60,000 Northern California customers Sunday night, aiming to mitigate wildfire risks from power lines during extreme winds.

Pacific Gas and Electric planned to restore power to 70 percent of affected customers in the North Bay and Sierra Foothills late Monday night. As crews inspect lines for safety by helicopter, vehicles and on foot, the remainder will have power sometime Tuesday.

While it was the first time the company shut off power for public safety, PG&E announced its criteria and procedures for such an event in June, said spokesperson Paul Doherty. After wildfires devastated Northern California's wine country last October, he added, PG&E developed its community wildfire safety program division to make power grids and communities more resilient, and prepares for winter storm season through enhanced local response. 

Two sagging PG&E power lines caused one of those wildfires during heavy winds, killing four people and injuring a firefighter, the California Department of Forestry and Fire Protection determined earlier this month. Trees or tree branches hitting PG&E power lines started another four wildfires in October 2017. Altogether, the power company has been blamed for igniting 13 wildfires last year.

"We're adapting our electric system our operating practices to improve safety and reliability," Doherty said of the safety program. "That's really the bottom line for us."

Turning off power to so many customers was a "last resort given the extreme fire danger conditions these communities are experiencing," Pat Hogan, senior vice president of electric operations, said in a statement. Conditions that led the company to shut off power included the National Weather Service's red flag fire warnings, humidity levels, sustained winds, temperature, dry fuel and local terrain, Doherty said, amid possible rolling blackouts during grid strain.

The company de-energized more than 78 miles of transmission lines and more than 2,150 miles of distribution power lines Sunday night. Many schools in the area were closed Monday because of the planned power outage, highlighting unequal access to electricity across communities.

Late Saturday and early Sunday, PG&E warned 97,000 customers in 12 counties that the shut off might go into effect. Through automated calls, texts and emails, the company encouraged customers to have drinking water, canned food, flashlights, prescriptions and baby supplies on hand.

Power was also turned off in Southern California on Monday.

San Diego Gas & Electric turned off service to about 360 customers near Cleveland National Forest, where multiple fires have scorched large swaths of land in recent years.

SDG&E has pre-emptively shut off power to customers in the past, most recently in December when 14,000 customers went without power.

Southern California Edison, the primary electric provider across Southern California — including Los Angeles — has a similar power shutoff program. As of Monday night, SCE had yet to turn off power in any of its service areas, a spokesperson told USA TODAY.

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