Wisconsin Power and Light dealt wind farm setback

Utility Pandemic Preparedness strengthens grid resilience through continuity planning, critical infrastructure protection, DOE-DHS coordination, onsite sequestration, skeleton crews, and deferred maintenance to ensure reliable electric and gas service for commercial and industrial customers.

Key Points

Plans that sustain grid operations during outbreaks using staffing limits, access controls, and deferred maintenance.

✅ Deferred maintenance and restricted site access

✅ Onsite sequestering and skeleton crew operations

✅ DOE-DHS coordination and control center staffing

Commercial and industrial businesses can rest assured that the current pandemic poses no real threat to our utilities, with the U.S. grid remaining reliable for now, as disaster planning has been key to electric and gas utilities in recent years, writes Forbes. Beginning a decade ago, the utility and energy industries evolved detailed pandemic plans, outlining what to know about the U.S. grid during outbreaks, which include putting off maintenance and routine activities until the worst of the pandemic has passed, restricting site access to essential personnel, and being able to run on a skeleton crew as more and more people become ill, a capability underscored by FPL's massive Irma response when crews faced prolonged outages.

One possible outcome of the current situation is that the US electric industry may require essential staff to live onsite at power plants and control centers, similar to Ontario work-site lockdown plans under consideration, if the outbreak worsens; bedding, food and other supplies are being stockpiled, reflecting local response preparations many utilities practice, Reuters reported. The Great River Energy cooperative, for example, has had a plan to sequester essential staff in place since the H1N1 bird flu crisis in 2009. The cooperative, which runs 10 power plants in Minnesota, says its disaster planning ensured it has enough cots, blankets and other necessities on site to keep staff healthy.

Electricity providers are now taking part in twice-weekly phone calls with officials at the DOE, the Department of Homeland Security, and other agencies, as Ontario demand shifts are monitored, according to the Los Angeles Times. By planning for a variety of worst case scenarios, including weeks-long restorations after major storms, “I have confidence that the sector will be prepared to respond no matter how this evolves,” says Scott Aaronson, VP of security and preparedness for the Edison Electric Institute.

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Great British Energy could cut UK electricity costs via public ownership, investing in clean energy like wind, solar, tidal, and nuclear, curbing windfall profits, stabilizing bills, and reinvesting returns through a state-backed generator.

Key Points

A proposed state-backed UK generator investing in clean power to cut costs and return gains to taxpayers.

✅ Publicly owned investment in wind, solar, tidal, and nuclear

✅ Cuts electricity bills by reducing generators' windfall profits

✅ Funded via bonds or asset buyouts; non-profit operations

A publicly owned electricity generation firm could save Britons nearly £21bn a year, according to new analysis that bolsters Labour’s case to launch a national energy company if the party gains power.

Thinktank Common Wealth has calculated that the cost of generating electricity to power homes and businesses could be reduced by £20.8bn or £252 per household a year under state ownership, according to a report seen by the Guardian.

The Labour leader, Keir Starmer, has committed to creating “a publicly owned national champion in clean energy” named Great British Energy.

Starmer is yet to lay out the exact structure of the mooted company, although he has said it would not involve nationalising existing assets, or become involved in the transmission grid or retail supply of energy.

Starmer instead hopes to create a state-backed entity that would invest in clean energy – wind, solar, tidal, nuclear, large-scale storage and other emerging technologies – creating jobs and ensuring windfalls from the growth in low carbon power feed back to the government.

The Common Wealth report, which analysed scenarios for reforming the electricity market, said that a huge saving on electricity costs could be made by buying out assets such as wind, solar and biomass generators on older contracts and running them on a non-profit basis. Funding the measure could require a government bond issuance, or some form of compulsory purchase process.

Last year the government attempted to get companies operating low carbon generators, including nuclear power plants, on older contracts to switch to contracts for difference (CfD), allowing any outsized profits to flow back to taxpayers. However, the government later decided to tax eligible firms through the electricity generator levy instead.

The Common Wealth study concluded that a publicly owned low carbon energy generator would best deliver on Britain’s climate and economic goals, would eliminate windfall profits made by generators and would cut household bills significantly.

MPs and campaigners have argued that Britain’s energy companies should be nationalised since the energy crisis, even as coal-free records have multiplied and renewables still need more support, which has resulted in North Sea oil and gas producers and electricity generators making windfall profits, and a string of retail suppliers collapsing, costing taxpayers billions. Detractors of nationalisation in energy argue it can stifle innovation and expose taxpayers to huge financial risks.

Common Wealth pointed out that more than 40% of the UK’s offshore wind generation capacity was publicly owned by overseas national entities, meaning the benefits of high electricity prices linked to the war in Ukraine had flowed back to other governments.

The study found the publicly owned generator model would create more savings than other options, including a drive for voluntary CfDs; splitting the generation market between low carbon and fossil fuel sources at a time when wind and solar have outproduced nuclear, and a “single buyer model” with nationalised retail suppliers.

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Electric weed-zapping farm robots enable precision agriculture, using autonomous mapping, per-plant targeting, and robotics to reduce pesticides, improve soil health, boost biodiversity, and lower costs with data-driven, selective weeding and seed-planting workflows.

Key Points

Autonomous machines that map fields, electrocute weeds per plant, and plant seeds, cutting pesticides, inputs, and costs.

✅ Precision agriculture: per-plant targeting reduces pesticide use up to 95%.

✅ Autonomous mapping robot surveys 20 hectares per day for weed data.

✅ Electric weeding and seeding improve soil health, biodiversity, and ROI.

On a field in England, three robots have been given a mission: to find and zap weeds with electricity, as advances in digitizing the electrical system continue to modernize power infrastructure, before planting seeds in the cleared soil.

The robots — named Tom, Dick and Harry — were developed by Small Robot Company to rid land of unwanted weeds with minimal use of chemicals and heavy machinery, complementing emerging options like electric tractors that aim to cut on-farm emissions.
The startup has been working on its autonomous weed killers since 2017, and this April launched Tom, its first commercial robot which is now operational on three UK farms. The other robots are still in the prototype stage, undergoing testing.

Small Robot says robot Tom can scan 20 hectares (49 acres) a day, collecting data, with AI-driven analysis guiding Dick, a "crop-care" robot, to zap weeds. Then it's robot Harry's turn to plant seeds in the weed-free soil.

Using the full system, once it is up and running, farmers could reduce costs by 40% and chemical usage by up to 95%, the company says, and integration with virtual power plants could further optimize energy use on electrified farms.

According to the UN Food and Agriculture Organization six million metric tons of pesticides were traded globally in 2018, valued at $38 billion.

"Our system allows farmers to wean their depleted, damaged soils off a diet of chemicals," says Ben Scott-Robinson, Small Robot's co-founder and CEO.

Zapping weeds
Small Robot says it has raised over £7 million ($9.9 million). Scott-Robinson says the company hopes to launch its full system of robots by 2023, which will be offered as a service at a rate of around £400 ($568) per hectare. The monitoring robot is placed at a farm first and the weeding and planting robots delivered only when the data shows they're needed — a setup that ultimately relies on a resilient grid, where research into preventing ransomware attacks is increasingly relevant.

To develop the zapping technology, Small Robot partnered with another UK-based startup, RootWave, while innovations like electricity from snow highlight the breadth of emerging energy tech.

"It creates a current that goes through the roots of the plant through the soil and then back up, which completely destroys the weed," says Scott-Robinson. "We can go to each individual plant that is threatening the crop plants and take it out."

"It's not as fast as it would be if you went out to spray the entire field," he says. "But you have to bear in mind we only have to go into the parts of the field where the weeds are." Plants that are neutral or beneficial to the crops are left untouched.

Small Robot calls this "per plant farming" — a type of precise agriculture where every plant is accounted for and monitored.

A business case
For Kit Franklin, an agricultural engineering lecturer from Harper Adams University, efficiency remains a hurdle, even as utilities use AI to adapt to electricity demands that could support wider on-farm electrification.

"There is no doubt in my mind that the electrical system works," he tells CNN Business. "But you can cover hundreds of hectares a day with a large-scale sprayer ... If we want to go into this really precise weed killing system, we have to realize that there is an output reduction that is very hard to overcome."

But Franklin believes farmers will adopt the technology if they can see a business case.

"There's a realization that farming in an environmentally friendly way is also a way of farming in an efficient way," he says. "Using less inputs, where and when we need them, is going to save us money and it's going to be good for the environment and the perception of farmers."

As well as reducing the use of chemicals, Small Robot wants to improve soil quality and biodiversity.

"If you treat a living environment like an industrial process, then you are ignoring the complexity of it," Scott-Robinson says. "We have to change farming now, otherwise there won't be anything to farm."

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Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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Texas Heat Pump Electrification replaces natural gas furnaces with electric heating across ERCOT, cutting carbon emissions, lowering utility bills, shifting summer peaks to winter, and aligning higher loads with strong seasonal wind power generation.

Key Points

Statewide shift from gas furnaces to heat pumps in Texas, reducing emissions and bills while moving grid peak to winter.

✅ Up to $452 annual utility savings per household

✅ CO2 cuts up to 13.8 million metric tons in scenarios

✅ Winter peak rises, summer peak falls; wind aligns with load

What would happen if you converted all the single-family homes in Texas from natural gas to electric heating?

According to a paper from Pecan Street, an Austin-based energy research organization, the transition would reduce climate-warming pollution, save Texas households up to $452 annually on their utility bills, and flip the state from a summer-peaking to a winter-peaking system. And that winter peak would be “nothing the grid couldn’t evolve to handle,” according to co-author Joshua Rhodes, a view echoed by analyses outlining Texas grid reliability improvements statewide today.

The report stems from the reality that buildings must be part of any comprehensive climate action plan.

“If we do want to decarbonize, eventually we do have to move into that space. It may not be the lowest-hanging fruit, but eventually we will have to get there,” said Rhodes.

Rhodes is a founding partner of the consultancy IdeaSmiths and an analyst at Vibrant Clean Energy. Pecan Street commissioned the study, which is distilled from a larger original analysis by IdeaSmiths, at the request of the nonprofit Environmental Defense Fund.

In an interview, Rhodes said, “The goal and motivation were to put bounding on some of the claims that have been made about electrification: that if we electrify a lot of different end uses or sectors of the economy...power demand of the grid would double.”

Rhodes and co-author Philip R. White used an analysis tool from the National Renewable Energy Laboratory called ResStock to determine the impact of replacing natural-gas furnaces with electric heat pumps in homes across the ERCOT service territory, which encompasses 90 percent of Texas’ electricity load.

Rhodes and White ran 80,000 simulations in order to determine how heat pumps would perform in Texas homes and how the pumps would impact the ERCOT grid.

The researchers modeled the use of “standard efficiency” (ducted, SEER 14, 8.2 HSPF air-source heat pump) and “superior efficiency” (ductless, SEER 29.3, 14 HSPF mini-split heat pump) heat pump models against two weather data sets — a typical meteorological year, and 2011, which had extreme weather in both the winter and summer and highlighted blackout risks during severe heat for many regions.

Emissions were calculated using Texas’ power sector data from 2017. For energy cost calculations, IdeaSmiths used 10.93 cents per kilowatt-hour for electricity and 8.4 cents per therm for natural gas.

Nothing the grid can't handle
Rhodes and White modeled six scenarios. All the scenarios resulted in annual household utility bill savings — including the two in which annual electricity demand increased — ranging from $57.82 for the standard efficiency heat pump and typical meteorological year to $451.90 for the high-efficiency heat pump and 2011 extreme weather year.

“For the average home, it was cheaper to switch. It made economic sense today to switch to a relatively high-efficiency heat pump,” said Rhodes. “Electricity bills would go up, but gas bills can go down.”

All the scenarios found carbon savings too, with CO2 reductions ranging from 2.6 million metric tons with a standard efficiency heat pump and typical meteorological year to 13.8 million metric tons with the high-efficiency heat pump in 2011-year weather.

Peak electricity demand in Texas would shift from summer to winter. Because heat pumps provide both high-efficiency space heating and cooling, in the scenario with “superior efficiency” heat pumps, the summer peak drops by nearly 24 percent to 54 gigawatts compared to ERCOT’s 71-gigawatt 2016 summer peak, even as recurring strains on the Texas power grid during extreme conditions persist.

The winter peak would increase compared to ERCOT’s 66-gigawatt 2018 winter peak, up by 22.73 percent to 81 gigawatts with standard efficiency heat pumps and up by 10.6 percent to 73 gigawatts with high-efficiency heat pumps.

“The grid could evolve to handle this. This is not a wholesale rethinking of how the grid would have to operate,” said Rhodes.

He added, “There would be some operational changes if we went to a winter-peaking grid. There would be implications for when power plants and transmission lines schedule their downtime for maintenance. But this is not beyond the realm of reality.”

And because Texas’ wind power generation is higher in winter, a winter peak would better match the expected higher load from all-electric heating to the availability of zero-carbon electricity.

A conservative estimate
The study presented what are likely conservative estimates of the potential for heat pumps to reduce carbon pollution and lower peak electricity demand, especially when paired with efficiency and demand response strategies that can flatten demand.

Electric heat pumps will become cleaner as more zero-carbon wind and solar power are added to the ERCOT grid, as utilities such as Tucson Electric Power phase out coal. By the end of 2018, 30 percent of the energy used on the ERCOT grid was from carbon-free sources.

According to the U.S. Energy Information Administration, three in five Texas households already use electricity as their primary source of heat, much of it electric-resistance heating. Rhodes and White did not model the energy use and peak demand impacts of replacing that electric-resistance heating with much more energy efficient heat pumps.

“Most of the electric-resistance heating in Texas is located in the very far south, where they don’t have much heating at all,” Rhodes said. “You would see savings in terms of the bills there because these heat pumps definitely operate more efficiently than electric-resistance heating for most of the time.”

Rhodes and White also highlighted areas for future research. For one, their study did not factor in the upfront cost to homeowners of installing heat pumps.

“More study is needed,” they write in the Pecan Street paper, “to determine the feasibility of various ‘replacement’ scenarios and how and to what degree the upgrade costs would be shared by others.”

Research from the Rocky Mountain Institute has found that electrification of both space and water heating is cheaper for homeowners over the life of the appliances in most new construction, when transitioning from propane or heating oil, when a gas furnace and air conditioner are replaced at the same time, and when rooftop solar is coupled with electrification, aligning with broader utility trends toward electrification.

More work is also needed to assess the best way to jump-start the market for high-efficiency all-electric heating. Rhodes believes getting installers on board is key.

“Whenever a homeowner’s making a decision, if their system goes out, they lean heavily on what the HVAC company suggests or tells them because the average homeowner doesn’t know much about their systems,” he said.

More work is also needed to assess the best way to jump-start the market for high-efficiency all-electric heating, and how utility strategies such as smart home network programs affect adoption too. Rhodes believes getting installers on board is key.

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TTC Winter E-Bike and E-Scooter Ban addresses lithium-ion battery safety, mitigating fire risk on Toronto public transit during cold weather across buses, subways, and streetcars, while balancing micro-mobility access, infrastructure gaps, and evolving regulations.

Key Points

A seasonal TTC policy limiting lithium-ion e-bikes and scooters on transit in winter to cut battery fire risk.

✅ Targets lithium-ion fire hazards in confined transit spaces

✅ Applies Nov-Mar across buses, subways, and streetcars

✅ Sparks debate on equity, accessibility, and policy alternatives

The Toronto Transit Commission (TTC) Board recently voted to implement a ban on lithium-ion-powered electric bikes (e-bikes) and electric scooters during the winter months, a decision that reflects growing safety concerns. This new policy has generated significant debate within the city, particularly regarding the role of these transportation modes in the lives of Torontonians, and the potential risks posed by the technology during cold weather.

A Growing Safety Concern

The move to ban lithium-ion-powered e-bikes and scooters from TTC services during the winter months stems from increasing safety concerns related to battery fires. Lithium-ion batteries, commonly used in e-bikes and scooters, are known to pose a fire risk, especially in colder temperatures, and as systems like Metro Vancouver's battery-electric buses expand, robust safety practices are paramount. In recent years, Toronto has experienced several high-profile incidents involving fires caused by these batteries. In some cases, these fires have occurred on TTC property, including on buses and subway cars, raising alarm among transit officials.

The TTC Board's decision was largely driven by the fear that the cold temperatures during winter months could make lithium-ion batteries more prone to malfunction, leading to potential fires. These batteries are particularly vulnerable to damage when exposed to low temperatures, which can cause them to overheat or fail during charging or use. Since public transit systems are densely populated and rely on close quarters, the risk of a battery fire in a confined space such as a bus or subway is considered too high.

The New Ban

The new rule, which is expected to take effect in the coming months, will prohibit e-bikes and scooters powered by lithium-ion batteries from being brought onto TTC vehicles, including buses, streetcars, and subway trains, even as the agency rolls out battery electric buses across its fleet, during the winter months. While the TTC had previously allowed passengers to bring these devices on board, it had issued warnings regarding their safety. The policy change reflects a more cautious approach to mitigating risk in light of growing concerns.

The winter months, typically from November to March, are when these batteries are at their most vulnerable. In addition to environmental factors, the challenges posed by winter weather—such as snow, ice, and the damp conditions—can exacerbate the potential for damage to these devices. The TTC Board hopes the new ban will prevent further incidents and keep transit riders safe.

Pushback and Debate

Not everyone agrees with the TTC Board's decision. Some residents and advocacy groups have expressed concern that this ban unfairly targets individuals who rely on e-bikes and scooters as an affordable and sustainable mode of transportation, while international examples like Paris's e-scooter vote illustrate how contentious rental devices can be elsewhere, adding fuel to the debate. E-bikes, in particular, have become a popular choice among commuters who want an eco-friendly alternative to driving, especially in a city like Toronto, where traffic congestion can be severe.

Advocates argue that instead of an outright ban, the TTC should invest in safer infrastructure, such as designated storage areas for e-bikes and scooters, or offer guidelines on how to safely store and transport these devices during winter, and, in assessing climate impacts, consider Canada's electricity mix alongside local safety measures. They also point out that other forms of electric transportation, such as electric wheelchairs and mobility scooters, are not subject to the same restrictions, raising questions about the fairness of the new policy.

In response to these concerns, the TTC has assured the public that it remains committed to finding alternative solutions that balance safety with accessibility. Transit officials have stated that they will continue to monitor the situation and consider adjustments to the policy if necessary.

Broader Implications for Transportation in Toronto

The TTC’s decision to ban lithium-ion-powered e-bikes and scooters is part of a broader conversation about the future of transportation in urban centers like Toronto. The rise of electric micro-mobility devices has been seen as a step toward reducing carbon emissions and addressing the city’s growing congestion issues, aligning with Canada's EV goals that push for widespread adoption. However, as more people turn to e-bikes and scooters for daily commuting, concerns about safety and infrastructure have become more pronounced.

The city of Toronto has yet to roll out comprehensive regulations for electric scooters and bikes, and this issue is further complicated by the ongoing push for sustainable urban mobility and pilots like driverless electric shuttles that test new models. While transit authorities grapple with safety risks, the public is increasingly looking for ways to integrate these devices into a broader, more holistic transportation system that prioritizes both convenience and safety.

The TTC’s decision to ban lithium-ion-powered e-bikes and scooters during the winter months is a necessary step to address growing safety concerns in Toronto's public transit system. Although the decision has been met with some resistance, it highlights the ongoing challenges in managing the growing use of electric transportation in urban environments, where initiatives like TTC's electric bus fleet offer lessons on scaling safely. With winter weather exacerbating the risks associated with lithium-ion batteries, the policy seeks to reduce the chances of fires and ensure the safety of all transit users. As the city moves forward, it will need to find ways to balance innovation with public safety to create a more sustainable and safe urban transportation network.

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