Ford factory processes paint fumes to generate power

Western Washington Bomb Cyclone unleashed gale-force winds, torrential rain, and coastal flooding, causing massive power outages from Seattle to Tacoma; storm surge, downed trees, and blocked roads hindered emergency response and infrastructure repairs.

Key Points

A rapidly deepening storm with severe winds, rain, flooding, and major power outages across Western Washington.

✅ Rapid barometric pressure drop intensified the system

✅ Gale-force winds downed trees and power lines

✅ Coastal flooding and storm surge disrupted transport

A powerful "bomb cyclone" recently hit Western Washington, causing widespread destruction across the region. The intense storm left more than half a million residents without power, similar to B.C. bomb cyclone outages seen to the north, with outages affecting communities from Seattle to Olympia. This weather phenomenon, marked by a rapid drop in atmospheric pressure, unleashed severe wind gusts, heavy rain, and flooding, causing significant disruption to daily life.

The bomb cyclone, which is a rapidly intensifying storm, typically features a sharp drop in barometric pressure over a short period of time. This creates extreme weather conditions, including gale-force winds, torrential rain, and coastal flooding, as seen during California storm impacts earlier in the season. In Western Washington, the storm struck just as the region was beginning to prepare for the winter season, catching many off guard with its strength and unpredictability.

The storm's impact was immediately felt as high winds downed trees, power lines, and other infrastructure. By the time the worst of the storm had passed, utility companies had reported widespread power outages, with more than 500,000 customers losing electricity. The outages were particularly severe in areas like Seattle, Tacoma, and the surrounding communities. Crews worked tirelessly in difficult conditions to restore power, but many residents faced extended outages, underscoring US grid climate vulnerabilities that complicate recovery efforts, with some lasting for days due to the scope of the damage.

The power outages were accompanied by heavy rainfall, leading to localized flooding. Roads were inundated, making it difficult for first responders and repair crews to reach affected areas. Emergency services were stretched thin as they dealt with downed trees, blocked roads, and flooded neighborhoods. In some areas, floodwaters reached homes, forcing people to evacuate. In addition, several schools were closed, and public transportation services were temporarily halted, leaving commuters stranded and businesses unable to operate.

As the storm moved inland, its effects continued to be felt. Western Washington’s coastal regions were hammered by high waves and storm surges, further exacerbating the damage. The combination of wind and rain also led to hazardous driving conditions, prompting authorities to advise people to stay off the roads unless absolutely necessary.

While power companies worked around the clock to restore electricity, informed by grid resilience strategies that could help utilities prepare for future events, challenges persisted. Fallen trees and debris blocked access to repair sites, and the sheer number of outages made it difficult for crews to restore power quickly. Some customers were left in the dark for days, forced to rely on generators, candles, and other makeshift solutions. The storm's intensity left a trail of destruction, requiring significant resources to address the damages and rebuild critical infrastructure.

In addition to the immediate impacts on power and transportation, the bomb cyclone raised important concerns about climate change and the increasing frequency of extreme weather events. Experts note that storms like these are becoming more common, with rapid intensification leading to more severe consequences and compounding pressures such as extreme-heat electricity costs for households. As the planet warms, scientists predict that such weather systems will continue to grow in strength, posing greater challenges to cities and regions that are not always prepared for such extreme events.

In the aftermath of the storm, local governments and utility companies faced the daunting task of not only restoring services but also assessing the broader impact of the storm on communities. Many areas, especially those hit hardest by flooding and power outages, will require substantial recovery efforts. The devastation of the bomb cyclone highlighted the vulnerability of infrastructure in the face of rapidly changing weather patterns and water availability, as seen in BC Hydro drought adaptations nearby, and reinforced the need for greater resilience in the face of future storms.

The storm's impact on the Pacific Northwest is a reminder of the power of nature and the importance of preparedness. As Western Washington recovers, there is a renewed focus on strengthening infrastructure, including expanded renewable electricity to diversify supply, improving emergency response systems, and ensuring that communities are better equipped to handle the challenges posed by increasingly severe weather events. For now, residents remain hopeful that the worst is behind them and are working together to rebuild and prepare for whatever future storms may bring.

The bomb cyclone has left an indelible mark on Western Washington, but it also serves as a call to action for better preparedness, more robust infrastructure, and a greater focus on combating climate change to mitigate the impact of such extreme weather in the future.

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Yukon Electricity Demand Record underscores peak load growth as winter cold snaps drive heating, lighting, and EV charging, blending hydro, LNG, and diesel with renewable energy and planned grid-scale battery storage in Whitehorse.

Key Points

It is the territory's new peak electricity load, reflecting winter demand, electric heating, EVs, and mixed generation.

✅ New peak: 104.42 MW, surpassing 2020 record of 103.84 MW

✅ Winter peaks met with hydro, LNG, diesel, and renewables mix

✅ Customers urged to shift use off peak hours and use timers

A new record for electricity demand has been set in Yukon. The territory recorded a peak of 104.42 megawatts, according to a news release from Yukon Energy.

The new record is about a half a megawatt higher than the previous record of 103.84 megawatts recorded on Jan. 14, 2020.

While in general, over 90 per cent of the electricity generated in Yukon comes from renewable resources each year, with initiatives such as new wind turbines expanding capacity, during periods of high electricity use each winter, Yukon Energy has to use its hydro, liquefied natural gas and diesel resources to generate the electricity, the release says.

But when it comes to setting records, Andrew Hall, CEO of Yukon Energy, says it's not that unusual.

"Typically, during the winter, when the weather is cold, demand for electricity in the Yukon reaches its maximum. And that's because folks use more electricity for heating their homes, for cooking meals, there's more lighting demand, because the days are shorter," he said.

"It usually happens either in December or sometimes in January, when we get a cold snap."

He said generally over the years, electricity demand has grown.

"We get new home construction, construction of new apartment buildings. And typically, those new homes are all heated by electricity, maybe not all of them but the majority," Hall said.

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Efforts to curb climate change add to electricity demand
There are also other reasons, ones that are "in the name of climate change," Hall added.

That includes people trying to limit fossil fuel heating by swapping to electric heating. And, he said some Yukoners are switching to electric vehicles as incentives expand across the North.

"Over time, those two new demands, in the name of climate change, will also contribute to growing demand for electricity," he said.

While Yukon did reach this new all time high, Hall said the territory still hadn't hit the maximum capacity for the week, which was 118 megawatts, and discussions about a potential connection to the B.C. grid are part of long-term planning.

Yukon Energy's hydroelectric dam in Whitehorse. Yukon Energy's CEO, Andrew Hall, said demand of 104 megawatts wasn't unexpected, nor was it an emergency. The corporation has the ability to generate 118 megawatts. (Paul Tukker/CBC)
Tips to curve demand
"When we plan our system, we actually plan for a scenario, guided by the view that sustainability is key to the grid's future, where we actually lose our largest hydro generating facility," Hall said.

"We had plenty of generation available so it wasn't an emergency situation, and, even as other provinces face electricity shortages, it was more just an observation that hey, our peaks are growing."

He also said it was an opportunity to reach out to customers on ways to curve their demand for electricity around peak times, drawing on energy efficiency insights from other provinces, which is typically between 7 a.m. and 9 a.m., and between 5 p.m. and 7 p.m., Monday to Friday.

For example, he said, people should consider running major appliances, like dishwashers, during non-peak hours, such as in the afternoon rather than in the morning or evening.

During winter peaks, people can also use a block heater timer on vehicles and turn down the thermostat by one or two degrees.

'We plan for each winter'
Hall said Yukon Energy is working to increase its peak output, including working on a large grid scale battery to be installed in Whitehorse, similar to Ontario's energy storage push now underway. 

When it comes to any added load from people working from home due to COVID-19, Hall said they haven't noticed any identifiable increase there.

"Presumably, if someone's working from home, you know, their computer is at home, and they're not using the computer at the office," he said.

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He said there shouldn't be any concern for maxing out the capacity of electricity demand as Yukon moves into the colder winter months, since those days are forecast for.

"This number of 104 megawatts wasn't unexpected," he said, adding how much electricity is needed depends on the weather too.

"We plan for each winter."

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Ontario-Quebec Electricity Trade Agreement ends as Ontario pivots to IESO procurement, hydropower alternatives, natural gas capacity, and energy auctions, impacting grid reliability, power imports, and GHG emissions across both provincial markets.

Key Points

A seven-year power import pact; Ontario will end it, shifting to IESO procurement and gas capacity.

✅ Seasonal hydropower exchange of 2.3 TWh annually.

✅ IESO projects Quebec supply constraints by decade end.

✅ Ontario adds gas, auctions; near-term sector GHGs rise.

The Ontario government does not plan to renew the Ontario-Quebec electricity trade agreement, Radio-Canada is reporting.

The seven-year contract, which expires next year, aims to reduce Ontario's greenhouse gas (GHG) emissions by buying 2.3 Terawatt-hours of electricity from Quebec annually — that corresponds to about seven per cent of Hydro-Quebec's average annual exports.

The announcement comes as the provincially owned Quebec utility continues its legal battle over a plan to export power to Massachusetts.

The Ontario agreement has guaranteed a seasonal exchange of energy, since Quebec has a power surplus in summer, and the province's electricity needs increase in the winter. Ontario plans on exercising its last and only option in the summer of 2026, for a block of 500 megawatts.

The office of the Ontario Minister of Energy Todd Smith says the province will save money by relying "on a competitive procurement process" instead, amid debates over clean, affordable electricity policy in Ontario. And, the Independent Electricity System Operator (IESO), the equivalent of Hydro-Quebec in Ontario, added that, at any rate, Quebec is expected to "run out of electricity in the middle or at the end of the decade."

During the Quebec election campaign, Premier Francois Legault said his province needed to increase hydroelectricity production because he is expecting demand for hydroelectricity to increase by an additional 100 terawatt-hours in the coming decades — half of Hydro-Quebec's current annual output.

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The provinces will still continue to buy and sell power, reaching deals through annual energy auctions.

Eloise Edom, an associate researcher at Polytechnique Montreal's Institut de l'energie Trottier, says the announcement came as somewhat of a surprise because "we're still talking about a lot of energy."

Hydro-Quebec refused to comment on "the SIERE [Independent Electricity System Operator]'s intentions for the agreement, which ends next year," said company spokesperson Lynn St-Laurent.

No green options
Yet Ontario is running out of electricity, even as questions persist about whether it is embracing clean power to meet demand, in part because of plans to refurbish nuclear reactors at the Bruce and Darlington generator stations.

Windsor has already lost out on a $2.5-billion factory because the region is short of electricity for new industrial loads. And by 2025, Toronto will run out of power for the electrification of its transit system, according to the latest estimates from the IESO.

The Ford government recently announced that it hopes to extend the life of the Pickering nuclear station amid ongoing debate. It is also evaluating the possibility of increasing hydroelectricity production at its existing dams.

For now, Ontario is banking on its natural gas plants to meet demand, which have won most recent IESO tenders for contracts running until 2026. Last Friday, the province announced that it was going to buy an additional 1,500 megawatts by 2027.

"The [Ontario energy] minister's expectations may be that the increase in natural gas prices is temporary and that it will fade," energy economist Jean-Thomas Bernard said. "With this in mind, he probably does not want to sign a long-term contract [with Hydro-Quebec] and prefers to buy electricity on a day-to-day basis and through calls for tenders."

If the Quebec deal expires, Ontario, Canada's second highest GHG emitter, would have to increase its emissions for the sector, at least in the medium term, with electricity getting dirtier as gas fills the gap.

Last year, the IESO found that it would be very difficult to set a moratorium on natural gas before 2030. The IESO must produce a final report on the subject for the energy minister by the end of November.

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UK Coal-Free Electricity Record highlights rapid growth in renewables as National Grid phases out coal; wind, solar, and offshore projects surge, green tariffs expand, and energy comparison helps consumers switch to cheaper, cleaner deals.

Key Points

Britain's longest coal-free run, enabled by renewables, lower demand, and grid shifts for cheaper, greener tariffs.

✅ Record set after two months without coal-fired generation

✅ Renewables outpace fossil fuels; wind and solar dominate

✅ Green tariffs expand; prices at three-year lows

On Wednesday 10 June, Britain hit a significant landmark: the UK went for two full months without burning coal to generate power – that's the longest period since the 1880s, following earlier milestones such as a full week without coal power in the recent past.

According to the National Grid, Britain has now run its electricity network without burning coal since midnight on the 9 April. This coal-free period has beaten the country’s previous record of 18 days, six hours and 10 minutes, which was set in June 2019, even though low-carbon generation stalled in 2019 according to analyses.

With such a shift in Britain’s drive for renewables and lower electricity demand following the coronavirus lockdown, as Britain recorded its cleanest electricity during lockdown to date, now may be the perfect time to do an online energy comparison and switch to a cheaper, greener deal.

Only a decade ago, around 40 per cent of Britain’s electricity came from coal generation, but since then the country has gradually shifted towards renewable energy, with the coal share at record lows in the system today. When Britain was forced into lockdown in response to the coronavirus pandemic, electricity demand dropped sharply, and the National Grid took the four remaining coal-fired plants off the network.

Over the past 10 years, Britain has invested heavily in renewable energy. Back in 2010, only 3 per cent of the country's electricity came from wind and solar, and many people remained sceptical. However, now, the UK has the biggest offshore wind industry in the world. Plus, last year, construction of the world’s single largest wind farm was completed off the coast of Yorkshire.

At the same time, Drax – Britain’s biggest power plant – has started to switch from burning coal to burning compressed wooden pellets instead, reflecting the UK's progress as it keeps breaking its coal-free energy record again across the grid. By this time next year, the plant hopes to have phased out coal entirely.

So far this year, renewables have generated more power than all fossil fuels put together, the BBC reports, and the energy dashboard shows the current mix in real time. Renewables have been responsible for 37 per cent of electricity supplied to the network, with wind and solar surpassing nuclear for the first time, while fossil fuels have accounted for 35 per cent. During the same period, nuclear accounted for 18 per cent and imports made up the remaining 10 per cent.

What does this mean for consumers?

As the country’s electricity supply moves more towards renewables, customers have more choice than ever before. Most of the ‘Big Six’ energy companies now have tariffs that offer 100 per cent green electricity. On top of this, specialist green energy suppliers such as Bulb, Octopus and Green Energy UK make it easier than ever to find a green energy tariff.

The good news is that our energy comparison research suggests that green energy doesn’t have to cost you more than a traditional fixed-price energy contract would. In fact, some of the cheapest energy suppliers are actually green companies.

At present, energy bills are at three-year lows, which means that now is the perfect time to switch supplier. As prices remain low and renewables begin to dominate the marketplace, more switchers will be drawn to green energy deals than ever before.

However, if you’re interested in choosing a green energy supplier, make sure that you look at the company's fuel mix. This way, you’ll be able to see whether they are guaranteeing the usage of green energy, or whether they’re just offsetting your usage. All suppliers must report how their energy is generated to Ofgem, so you’ll easily be able to compare providers.

You may find that you pay more for a supplier that generates its own energy from renewables, or pay less if the supplier simply matches your usage by buying green energy. You can decide which option is right for you after comparing the prices.

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Western Denmark Negative Electricity Prices stem from wind energy oversupply, grid congestion, and limited interconnector capacity via Nord Pool and TenneT, underscoring electrification needs, renewable integration, special regulation, and system flexibility.

Key Points

They are sub-zero power prices from wind oversupply, weak interconnectors, low demand, and balancing needs.

✅ Caused by high wind output, low demand, and export bottlenecks

✅ Limited Nord Pool interconnector capacity depresses prices

✅ Special regulation and district heating absorb excess power

A downturn in the cable connection to Norway and Sweden, together with low electricity consumption and high electricity production, has pushed down European electricity prices to a negative level in Western Denmark.

A sign that the electrification of society is urgently needed, says Soren Klinge, head of electricity market at Wind Denmark today.

The heavy winds during the first weekend of July, unlike periods when cheap wind power wanes in the UK, have not only had consequences for the Danes who had otherwise been looking forward to spending their first days at home in the garden or at the beach. It has also pushed down prices in the electricity market to a negative level, which especially the West Danish wind turbine owners have had to notice.

'The electricity market is currently affected by an unfortunate coincidence of various factors that have a negative impact on the electricity price: a reduced export capacity to the other Nordic countries, a low electricity consumption and a high electricity generation, reflecting broader concerns over dispatchable power shortages in Europe today. Unfortunately, the coincidence of these three factors means that the price base falls completely out of the market. This is another sign that the electrification of society is urgently needed, 'explains Soren Klinge, electricity market manager at Wind Denmark.

According to the European power exchange Nord Pool Spot, where UK peak power prices are also tracked, the cable connection to Sweden is expected to return to full capacity from 19 July. The connection between Jutland and Norway is only expected to return to full capacity in early September.

2000 MWh / hour in special regulation

During the windy weather on Monday morning, July 6, up to 2000 MWh / hour was activated at national level in the form of so-called special regulation. Special regulation is the designation that the German system operator TenneT switches off Danish electricity generation at cogeneration plants and wind turbines in order to help with the balancing of the German power system during such events. In addition, electric boilers at the cogeneration plants also contribute by using the electricity from the electricity grid and converting it to district heating for the benefit of Danish homes and businesses.

'The Danish wind turbines are probably the source of most of the special regulation, because there are very few cogeneration units to down-regulate electricity generation. Of course, it is positive to see that we have a high degree of flexibility in the wind-based power system at home. That being said, Denmark does not really get ahead with the green transition, even as its largest energy company plans to stop using coal by 2023, until we are able to raise electricity consumption based on renewable energy.

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Philippines Nuclear Energy Policy aims to add nuclear power to the energy mix via executive order, meeting rising electricity demand with 24/7 baseload while balancing safety, renewables, and imported fuel dependence in the Philippines.

Key Points

A government plan to include nuclear power in the energy mix to meet demand, ensure baseload, and uphold safety.

✅ Executive order proposed by Energy Secretary Alfonso Cusi

✅ Targets 24/7 baseload, rising electricity demand

✅ Balances safety, renewables, and energy security

Phillipines Presidential spokesman Salvador Panelo said Energy Secretary Alfonso Cusi made the proposal during last Monday's Cabinet meeting in Malacaaang. "Secretary Cusi likewise sought the approval of the issuance of a proposed executive order for the inclusion of nuclear power, including next-gen nuclear options in the country's energy mix as the Philippines is expected to the rapid growth in electricity and electricity demand, in which, 24/7 power is essential and necessary," Panelo said in a statement.

Panelo said Duterte would study the energy chief's proposal, as China's nuclear development underscores regional momentum. In the 1960s until the mid 80s, the late president Ferdinand Marcos adopted a nuclear energy program and built the Bataan Nuclear Plant.

The nuclear plant was mothballed after Corazon Aquino became president in 1986. There have been calls to revive the nuclear plant, saying it would help address the Philippines' energy supply issues. Some groups, however, said such move would be expensive and would endanger the lives of people living near the facility, citing Three Mile Island as a cautionary example.

Panelo said proposals to revive the Bataan Nuclear Plant were not discussed during the Cabinet meeting, even as debates like California's renewable classification continue to shape perceptions. Indigenous energy sources natural gas, hydro, coal, oil, geothermal, wind, solar, biomassand ethanol constitute more than half or 59.6%of the Philippines' energy mix.

Imported oil make up 31.7% while imported coal, reflecting the country's coal dependency, contribute about 8.7%.

Imported ethanol make up 0.1% of the energy mix, even as interest in atomic energy rises globally.

In 2018, Duterte said safety should be the priority when deciding whether to tap nuclear energy for the country's power needs, as countries like India's nuclear restart proceed with their own safeguards.

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