Dounreay nuclear waste was dumped in the sea over a period of 20 years

British Columbia electricity rate increase will raise BC Hydro bills 3.75% over 2025-2026 to fund infrastructure, Site C, and clean energy, balancing affordability, reliability, and energy security while keeping prices below the North American average.

Key Points

BC will raise BC Hydro rates 3.75% in 2025-2026, about $3.75/month, to fund grid upgrades, Site C, and clean energy.

✅ 3.75% over 2025-2026; about $3.75/month on $100 average bill

✅ Funds Site C, grid maintenance, and clean energy capacity

✅ Keeps BC Hydro rates below North American averages

British Columbia's electricity rates will experience a 3.75% increase over the next two years, following an earlier 3% rate increase approval that set the stage, as confirmed by the provincial government on March 17, 2025. The announcement was made by Minister of Energy and Climate Solutions, Adrian Dix, who emphasized the decision's necessity for maintaining BC Hydro’s infrastructure while balancing affordability for residents.

For most households, the increase will amount to an additional $3.75 per month, based on an average BC Hydro bill of $100, though some coverage framed an earlier phase as a BC Hydro $2/month proposal that later evolved. While this may seem modest, the increase reflects a broader strategy to stabilize the utility's rates amidst economic challenges and ensure long-term energy security for the province.

Reasons Behind the Rate Hike

The rate increase comes during a period of rising costs in both global markets and local economies. According to Dix, the economic uncertainty stemming from trade dynamics and inflation has forced the government to act. Despite these pressures, and after a prior B.C. rate freeze to moderate impacts, the increase remains below cumulative inflation over the last several years, a move designed to shield consumers from the full force of these economic changes.

Dix also noted that, when adjusted for inflation, electricity rates in British Columbia in 2025 are effectively at the same price they were four decades ago. This stability, he argued, underscores the provincial government’s commitment to keeping rates as low as possible for residents, even as operating costs rise.

“We must take urgent action to protect British Columbians from the uncertainty posed by rising costs while building a strong, resilient electricity system for the long-term benefit of B.C.’s energy independence,” Dix said. He also highlighted the government's approach to minimizing the financial burden on consumers by keeping electricity costs well below the North American average.

Infrastructure and Maintenance Costs

The primary justification for the rate increase is to allow BC Hydro to continue its critical infrastructure development, including the Site C hydroelectric project, which is expected to become operational in the coming years. The increased costs of maintaining and upgrading the province's electricity grid also contribute to the need for higher rates.

The Site C project, a massive hydroelectric dam under construction on the Peace River, is expected to provide a substantial increase in clean, renewable energy capacity. However, such large-scale projects require significant investment and maintenance, both of which have contributed to the increased operating costs for BC Hydro.

A Strategic Move for Rate Stability

The provincial government has been clear that the rate increase will allow for a continuation of infrastructure development while keeping the rates manageable for consumers. The 3.75% increase will be spread across two years, with the first hike scheduled for April 1, 2025, reflecting the typical April rate changes BC Hydro implements, and the second for April 1, 2026.

Dix confirmed that the rate hike would still keep electricity costs among the lowest in North America, noting that British Columbians pay about half of what residents in Alberta pay for electricity. This is part of a broader effort by the provincial government to provide stable energy pricing while bolstering the transition to clean energy solutions, such as the Site C project and other renewable energy initiatives.

Addressing Public Concerns

Although the government has framed the increase as a necessary measure to ensure the province's long-term energy independence and reliability, the rate hikes are likely to face scrutiny from residents, particularly those already struggling with the rising cost of living, even as provinces like Ontario face their own Ontario hydro rate increase pressures this fall.

Public reactions to utility rate increases are often contentious, as residents feel the pressure of rising prices across various sectors, from housing to healthcare. However, the government has promised that the new rates will remain manageable, especially considering the relatively low rate increases compared to inflation and other regions where Manitoba Hydro scaled back a planned increase to temper impacts.

Furthermore, the increase comes as part of a broader strategy that aims to keep the overall impact on consumers as low as possible. Minister Dix emphasized that these rate increases were intended to ensure the continued reliability of BC Hydro’s services, without overwhelming ratepayers.

Long-Term Goals

Looking ahead, the province's strategy centers on not only maintaining affordable electricity rates but also reinforcing the importance of renewable energy, while some jurisdictions consider a 2.5% annual increase plan over multiple years to stabilize their grids. As climate change becomes an increasingly pressing issue, BC’s investments in clean energy projects like Site C aim to provide sustainable power for generations to come.

The government’s long-term vision involves building a resilient, energy-independent province that can weather future economic and environmental challenges. In this context, the rate increases are framed not just as a response to immediate inflationary pressures but as a necessary step in preparing BC’s energy infrastructure for the future.

The 3.75% rate increase set for 2025 and 2026 represents a balancing act between managing the financial health of BC Hydro and protecting consumers from higher costs. While the increase will have a modest effect on household bills, the long-term goal is to build a more robust and sustainable electricity system for British Columbia’s future. Through investments in clean energy and strategic infrastructure development, the province aims to keep electricity rates competitive while positioning itself as a leader in energy independence and climate action.

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Smart EV Charging orchestrates vehicle-to-grid (V2G), demand response, and fast charging to balance the power grid, integrating renewables, electrolyzers for hydrogen, and megawatt chargers for fleets with advanced control and co-optimization.

Key Points

Smart EV charging coordinates EV load to stabilize the grid, cut peaks, and integrate renewable energy efficiently.

✅ Reduces peak demand via coordinated, flexible load control

✅ Enables V2G services with renewables and battery storage

✅ Supports megawatt fast charging for heavy-duty fleets

As electric vehicle (EV) sales continue to rev up in the United States, the power grid is in parallel contending with the greatest transformation in its 100-year history: the large-scale integration of renewable energy and power electronic devices. The expected expansion of EVs will shift those challenges into high gear, causing cities to face gigawatt-growth in electricity demand, as analyses of EV grid impacts indicate, and higher amounts of variable energy.

Coordinating large numbers of EVs with the power system presents a highly complex challenge. EVs introduce variable electrical loads that are highly dependent on customer behavior. Electrified transportation involves co-optimization with other energy systems, like natural gas and bulk battery storage, including mobile energy storage flexibility for new operational options. It could involve fleets of automated ride-hailing EVs and lead to hybrid-energy truck stops that provide hydrogen and fast-charging to heavy-duty vehicles.

Those changes will all test the limits of grid integration, but the National Renewable Energy Laboratory (NREL) sees opportunity at the intersection of energy systems and transportation. With powerful resources for simulating and evaluating complex systems, several NREL projects are determining the coordination required for fast charging, balancing electrical supply and demand, and efficient use of all energy assets.

Smart and Not-So-Smart Control
To appreciate the value of coordinated EV charging, it is helpful to imagine the opposite scenario.

"Our first question is how much benefit or burden the super simple, uncoordinated approach to electric vehicle charging offers the grid," said Andrew Meintz, the researcher leading NREL's Electric Vehicle Grid Integration team, as well as the RECHARGE project for smart EV charging. "Then we compare that to the 'whiz-bang,' everything-is-connected approach. We want to know the difference in value."

In the "super simple" approach, Meintz explained that battery-powered electric vehicles grow in market share, exemplified by mass-market EVs, without any evolution in vehicle charging coordination. Picture every employee at your workplace driving home at 5 p.m. and charging their vehicle. That is the grid's equivalent of going 0 to 100 mph, and if it does not wreck the system, it is at least very expensive. According to NREL's Electrification Futures Study, a comprehensive analysis of the impacts of widespread electrification across all U.S. economic sectors, in 2050 EVs could contribute to a 33% increase in energy use during peak electrical demand, underscoring state grid challenges that make these intervals costly when energy reserves are procured. In duck curve parlance, EVs will further strain the duck's neck.

The Optimization and Control Lab's Electric Vehicle Grid Integration bays allow researchers to determine how advanced high power chargers can be added safely and effectively to the grid, with the potential to explore how to combine buildings and EV charging. Credit: Dennis Schroeder, NREL
Meintz's "whiz-bang" approach instead imagines EV control strategies that are deliberate and serve to smooth, rather than intensify, the upcoming demand for electricity. It means managing both when and where vehicles charge to create flexible load on the grid.

At NREL, smart strategies to dispatch vehicles for optimal charging are being developed for both the grid edge, where consumers and energy users connect to the grid, as in RECHARGEPDF, and the entire distribution system, as in the GEMINI-XFC projectPDF. Both projects, funded by the U.S. Department of Energy's (DOE's) Vehicle Technologies Office, lean on advanced capabilities at NREL's Energy Systems Integration Facility to simulate future energy systems.

At the grid edge, EVs can be co-optimized with distributed energy resources—small-scale generation or storage technologies—the subject of a partnership with Eaton that brought industry perspectives to bear on coordinated management of EV fleets.

At the larger-system level, the GEMINI-XFC project has extended EV optimization scenarios to the city scale—the San Francisco Bay Area, to be specific.

"GEMINI-XFC involves the highest-ever-fidelity modeling of transportation and the grid," said NREL Research Manager of Grid-Connected Energy Systems Bryan Palmintier.

"We're combining future transportation scenarios with a large metro area co-simulationPDF—millions of simulated customers and a realistic distribution system model—to find the best approaches to vehicles helping the grid."

GEMINI-XFC and RECHARGE can foresee future electrification scenarios and then insert controls that reduce grid congestion or offset peak demand, for example. Charging EVs involves a sort of shell game, where loads are continually moved among charging stations to accommodate grid demand.

But for heavy-duty vehicles, the load is harder to hide. Electrified truck fleets will hit the road soon, creating power needs for electric truck fleets that translate to megawatts of localized demand. No amount of rerouting can avoid the requirements of charging heavy-duty vehicles or other instances of extreme fast-charging (XFC). To address this challenge, NREL is working with industry and other national laboratories to study and demonstrate the technological buildout necessary to achieve 1+ MW charging stationsPDF that are capable of fast charging at very high energy levels for medium- and heavy-duty vehicles.

To reach such a scale, NREL is also considering new power conversion hardware based on advanced materials like wide-bandgap semiconductors, as well as new controllers and algorithms that are uniquely suited for fleets of charge-hungry vehicles. The challenge to integrate 1+ MW charging is also pushing NREL research to higher power: Upcoming capabilities will look at many-megawatt systems that tie in the support of other energy sectors.

Renewable In-Roads for Hydrogen

At NREL, the drive toward larger charging demands is being met with larger research capabilities. The announcement of ARIES opens the door to energy systems integration research at a scale 10-times greater than current capabilities: 20 MW, up from 2 MW. Critically, it presents an opportunity to understand how mobility with high energy demands can be co-optimized with other utility-scale assets to benefit grid stability.

"If you've got a grid humming along with a steady load, then a truck requires 500 kW or more of power, it could create a large disruption for the grid," said Keith Wipke, the laboratory program manager for fuel cells and hydrogen technologies at NREL.

Such a high power demand could be partially served by battery storage systems. Or it could be hidden entirely with hydrogen production. Wipke's program, with support from the DOE's Hydrogen and Fuel Cell Technologies Office, has been performing studies into how electrolyzers—devices that use electricity to break water into hydrogen and oxygen—could offset the grid impacts of XFC. These efforts are also closely aligned with DOE's H2@Scale vision for affordable and effective hydrogen use across multiple sectors, including heavy-duty transportation, power generation, and metals manufacturing, among others.

"We're simulating electrolyzers that can match the charging load of heavy-duty battery electric vehicles. When fast charging begins, the electrolyzers are ramped down. When fast charging ends, the electrolyzers are ramped back up," Wipke said. "If done smoothly, the utility doesn't even know it's happening."

NREL Researchers Rishabh Jain, Kazunori Nagasawa, and Jen Kurtz are working on how grid integration of electrolyzers—devices that use electricity to break water into hydrogen and oxygen—could offset the grid impacts of extreme fast-charging. Credit: National Renewable Energy Laboratory
As electrolyzers harness the cheap electrons from off-demand periods, a significant amount of hydrogen can be produced on site. That creates a natural energy pathway from discount electricity into a fuel. It is no wonder, then, that several well-known transportation and fuel companies have recently initiated a multimillion-dollar partnership with NREL to advance heavy-duty hydrogen vehicle technologies.

"The logistics of expanding electric charging infrastructure from 50 kW for a single demonstration battery electric truck to 5,000 kW for a fleet of 100 could present challenges," Wipke said. "Hydrogen scales very nicely; you're basically bringing hydrogen to a fueling station or producing it on site, but either way the hydrogen fueling events are decoupled in time from hydrogen production, providing benefits to the grid."

The long driving range and fast refuel times—including a DOE target of achieving 10-minutes refuel for a truck—have already made hydrogen the standout solution for applications in warehouse forklifts. Further, NREL is finding that distributed electrolyzers can simultaneously produce hydrogen and improve voltage conditions, which can add much-needed stability to a grid that is accommodating more energy from variable resources.

Those examples that co-optimize mobility with the grid, using diverse technologies, are encouraging NREL and its partners to pursue a new scale of systems integration. Several forward-thinking projects are reimagining urban mobility as a mix of energy solutions that integrate the relative strengths of transportation technologies, which complement each other to fill important gaps in grid reliability.

The Future of Urban Mobility
What will electrified transportation look like at high penetrations? A few NREL projects offer some perspective. Among the most experimental, NREL is helping the city of Denver develop a smart community, integrated with electrified mobility and featuring automated charging and vehicle dispatch.

On another path to advanced mobility, Los Angeles has embarked on a plan to modernize its electricity system infrastructure, reflecting California EV grid stability goals—aiming for a 100% renewable energy supply by 2045, along with aggressive electrification targets for buildings and vehicles. Through the Los Angeles 100% Renewable Energy Study, the city is currently working with NREL to assess the full-scale impacts of the transition in a detailed analysis that integrates diverse capabilities across the laboratory.

The transition would include the Port of Long Beach, the busiest container port in the United States.

At the port, NREL is applying the same sort of scenario forecasting and controls evaluation as other projects, in order to find the optimal mix of technologies that can be integrated for both grid stability and a reliable quality of service: a mix of hydrogen fuel-cell and battery EVs, battery storage systems, on-site renewable generation, and extreme coordination among everything.

"Hydrogen at ports makes sense for the same reason as trucks: Marine applications have big power and energy demands," Wipke said. "But it's really the synergies between diverse technologies—the existing infrastructure for EVs and the flexibility of bulk battery systems—that will truly make the transition to high renewable energy possible."

Like the Port of Long Beach, transportation hubs across the nation are adapting to a complex environment of new mobility solutions. Airports and public transit stations involve the movement of passengers, goods, and services at a volume exceeding anywhere else. With the transition to digitally connected electric mobility changing how airports plan for the future, NREL projects such as Athena are using the power of high-performance computing to demonstrate how these hubs can maximize the value of passenger and freight mobility per unit of energy, time, and/or cost.

The growth in complexity for transportation hubs has just begun, however. Looking ahead, fleets of ride-sharing EVs, automated vehicles, and automated ride-sharing EV fleets could present the largest effort to manage mobility yet.

A Self-Driving Power Grid
To understand the full impact of future mobility-service providers, NREL developed the HIVE (Highly Integrated Vehicle Ecosystem) simulation framework. HIVE combines factors related to serving mobility needs and grid operations—such as a customer's willingness to carpool or delay travel, and potentially time-variable costs of recharging—and simulates the outcome in an integrated environment.

"Our question is, how do you optimize the management of a fleet whose primary purpose is to provide rides and improve that fleet's dispatch and charging?" said Eric Wood, an NREL vehicle systems engineer.

HIVE was developed as part of NREL's Autonomous Energy Systems research to optimize the control of automated vehicle fleets. That is, optimized routing and dispatch of automated electric vehicles.

The project imagines how price signals could influence dispatch algorithms. Consider one customer booking a commute through a ride-hailing app. Out of the fleet of vehicles nearby—variously charged and continually changing locations—which one should pick up the customer?

Now consider the movements of thousands of passengers in a city and thousands of vehicles providing transportation services. Among the number of agents, the moment-to-moment change in energy supply and demand, and the broad diversity in vendor technologies, "we're playing with a lot of parameters," Wood said.

But cutting through all the complexity, and in the midst of massive simulations, the end goal for vehicle-to-grid integration is consistent:

"The motivation for our work is that there are forecasts for significant load on the grid from the electrification of transportation," Wood said. "We want to ensure that this load is safely and effectively integrated, while meeting the expectations and needs of passengers."

The Port of Long Beach uses a mix of hydrogen fuel-cell and battery EVs, battery storage systems, on-site renewable generation, and extreme coordination among everything. Credit: National Renewable Energy Laboratory
True Replacement without Caveats

Electric vehicles are not necessarily helpful to the grid, but they can be. As EVs become established in the transportation sector, NREL is studying how to even out any bumps that electrified mobility could cause on the grid and advance any benefits to commuters or industry.

"It all comes down to load flexibility," Meintz said. "We're trying to decide how to optimally dispatch vehicle charging to meet quality-of-service considerations, while also minimizing charging costs."

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Lockdown Electricity Demand Trends reveal later mornings, weaker afternoons, and delayed peaks as WFH, streaming, and video conferencing reshape energy demand curves, grid forecasting, and residential electricity usage across Europe, New York, Tokyo, and Singapore.

Key Points

Shifts in power use during lockdowns: later ramps, weaker afternoons, and higher, delayed evening peaks.

✅ Morning ramp starts later; midday demand dips

✅ Evening peak shifts 1-2 hours; higher late-night usage

✅ WFH and streaming raise residential load; industrial demand falls

Life in lockdown means getting up late, staying up till midnight and slacking off in the afternoons.

That’s what power market data in Europe show in the places where restrictions on activity have led to a widespread shift in daily routines of hundreds of millions of people.

It’s a similar story wherever lockdowns bite. In New York City electricity use has fallen as much as 18% from normal times at 8am. Tokyo and three nearby prefectures had a 5% drop in power use during weekdays after Japan declared a state of emergency on April 7, according to Tesla Asia Pacific, an energy forecaster.

Italy’s experience shows the trend most clearly since the curbs started there on March 5, before any other European country. Data from the grid operator Terna SpA gives a taste of what other places are also now starting to report, with global daily demand dips observed in many markets as well.

1. People are sleeping later

With no commute to the office people can sleep longer. Normally, electricity demand began to pick up between 6 a.m. and 8 a.m. Now in Germany, it’s clear coffee machines don’t go on until between 8 a.m. and 9 a.m., said Simon Rathjen, founder of the trading company MFT Energy A/S.

Germany, France and Italy -- which between them make up almost two thirds of the euro-zone economy -- all have furlough measures that allow workers to receive a salary while temporarily suspended from their jobs. The U.K. also has a support package. Many of these workers will be getting up later.

"Now I have quite a relaxed start to the morning,” said David Freeman, an analyst in financial services from London. "I don’t get up until about half an hour before I need to start work.”

2. Less productive afternoons

There is a deeper dip in electricity use in the afternoons. Previously, power use rose between 2pm and 5pm. Now it dips as people head out for a walk or some air, according to UK demand data from National Grid Plc

It’s "as though we are living through a month of Sundays”, said Iain Staffell, senior lecturer in sustainable energy at Imperial College London.

3. Evenings in

From 6pm electricity use begins to rise steeply as people finish work and start chores. Restrictions like work and home schooling that prevent much daytime TV watching lifts in the early evening. This following chart for Germany shows the evening peak for power use coming during later hours.

The evening is when electricity use is highest, with most people confined to their homes. Netflix Inc reported a record 15.8 million paid subscribers – almost double the figure forecast by Wall Street analysts. Video-streaming services like Netflix and YouTube have found a captive audience. The new Disney+ service surpassed 50 million subscribers in just five months, a faster pace than predicted.

Internet traffic is skyrocketing, with a surge in bandwidth-intensive applications like streaming services and Zoom. This may mean that monthly broadband consumption of as much as 600 gigabytes, about 35% higher than before, according to Bloomberg Intelligence.

In Singapore, electricity use has dropped off significantly since the country’s "circuit-breaker” efforts to keep people at home began April 7. Electricity use has fallen and stayed low during the day. But late at night is a different story, as power demand fell sharply immediately after the lockdown began, it has steadily crept back in the past two weeks, perhaps a sign that Tiger King and The Last Dance have been finding late-night fans in the city state.

In Ottawa, COVID-19 closures made it seem as if the city had fallen off the electricity grid, according to local reports.

4. Staying up late

We’re going to bed later too. Demand doesn’t start to drop off until 10pm to 12am, at least an hour later than before.

"My children are definitely going to bed later,” said Liz Stevens, a teaching assistant from London. "Our whole routine is out the window.”

It’s challenging for those that need to predict behaviour – power grids and electricity traders. Forecasting is based on historical data, and there isn’t anything to go into the models gauging use now.

The closest we can get is looking at big events like football World Championships when people are all sitting down at the same time, according to Rathjen at MFT.

"Forecasting demand right now is very tricky,” said Chris Kimmett, director of power grids at Reactive Technologies Ltd. "A global pandemic is uncharted territory."

What normal looks like when the crisis passes is also an open question. Different countries are set to unravel their measures in their own ways, and global power demand has already surged above pre-pandemic levels in some analyses, with Germany and Austria loosening restrictions first and Italy remaining under tight control. Some changes may be permanent, with both workers and employers becoming more comfortable with working from home.

5. Different sectors consume more

In China, which is further along recovering from the pandemic than Europe or the US, the sharp contraction in overall power output masks a shift in daily routines.

Eating habits have changed. Restaurants are expanding delivery and even offering grocery services as the preference for dining at home persists. Household electricity consumption in China probably increased from activities such as cooking and heating, according to IHS Markit, which said that residential demand rose by 2.4% in the first two months as people stayed in.

The increase in technology use also drove China’s power demand from the telecom and web-service sectors to rise by 27%, the consultancy said.

Overall, China power demand in the first quarter of the year fell 6.5% from the same period in 2019 to 1.57 trillion kilowatt-hours, China’s National Energy Administration said last week. Industry uses about 70% of the country’s electricity, while the commercial sector and households account for 14% each. – Bloomberg

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Cold-Climate Heat Pumps deliver efficient heating and cooling for Northern B.C. Net Zero Ready homes, with air-source Mitsubishi H2i systems, triple-pane windows, blower door ACH 0.8, BC Hydro rebates, and CleanBC incentives.

Key Points

Electric air-source systems that heat and cool in subzero climates, cutting emissions and lowering energy costs.

✅ Net Zero Ready, Step Code 5, ACH 0.8 airtightness

✅ Operate efficiently to about -28 C with backup heat

✅ Eligible for BC Hydro and CleanBC rebates

Heat pump provides heating, cooling in northern B.C. home
It's a tradition at Vanderhoof-based Northern Homecraft that, on the day of the blower door test for a just-completed home, everyone who worked on the build gathers to watch it happen. And in the spring of 2021, on a dazzling piece of land overlooking the mouth of the Stuart River near Fort St. James, that day was a cause for celebration.

A new 3,400-square foot home subjected to the blower door test – a diagnostic tool to determine how much air is entering or escaping from a home – was rated as having just .8 air changes per hour (ACH). That helps make it a Net Zero Ready home, and BC Energy Code Step 5 compliant. That means it would take about a third of the amount of energy to heat the home compared to a typical similar-sized home in B.C. today.

From an energy-efficiency perspective, this is a home whose evident beauty is anything but skin deep.

"The home has lot of square footage of finished living space, and it also has a lot of glazing," says Northern Homecraft owner Shay Bulmer, referring to the home's large windows. "We had a lot of window space to deal with, as well as large vaulted open areas where you can only achieve so much additional insulation. There were a few things that the home had going against it as far as performance goes. There were challenges in keeping it comfortable year-round."

Well-insulated home ideal for heat pump option
Most homes in colder areas of B.C. lean on gas-fueled heating systems to deal with the often long, chilly winters. But with the arrival of cold climate heat pumps capable of providing heat efficiently when temperatures dip as low as -30°C, there's now a clean option for those homes, and using more electricity for heat is gaining support in the North as well.

Heat pumps are an increasingly popular option, both for new and existing homes, because they avoid carbon emissions associated with fossil use while also offering summer cooling, even as record-high electricity demand in Yukon underscores the need for efficient systems.

The Fort St. James home, which was built with premium insulation, airtightness and energy efficiency in mind, made the decision to opt for a heat pump even easier. Still, the heat pump option took the home's owners Dexter and Cheryl Hodder by surprise. While their focus was on designing a home that took full advantage of views down to the river, the couple was under the distinct impression that heat pumps couldn't cut it in the chilly north.

"I wasn't really considering a heat pump, which I thought was only a good solution in a moderate climate," says Dexter, who as director of research and education for the John Prince Research Forest, studies wildlife and forestry interactions in north central B.C. "The specs on the heat pump indicate it would work down to -28°C, and I was skeptical of that. But it worked exactly to spec. It almost seems ridiculous to generate heat from outside air at those low temperatures, but it does."

Getting it right with support and rebates
Northern Homecraft took advantage of BC Hydro's Mechanical System Design Pilot program to ensure proper heat pump system design, installation, and verification for the home were applied, and with BC Hydro's first call for power in 15 years driven by electrification, the team prioritized efficient load management.

Based on the home's specific location, size, and performance targets, they installed a ducted Mitsubishi H2I air-source heat pump system. Windows are triple pane, double coated, and a central feature of the home, while insulation specifications were R-40 deep frame insulation in the exterior walls, R-80 insulation in the attic, and R-40 insulation in the vaulted ceilings.

The combination of the year-round benefits of heat pumps, their role in reducing fossil fuel emissions, and the availability of rebates, is making the systems increasingly attractive in B.C., especially as two new BC generating stations were recently commissioned to expand clean supply.

BC Hydro offers home renovation rebates of up to $10,000 for energy-efficient upgrades to existing homes. Rebates are available for windows and doors, insulation, heat pumps, and heat pump hot water heaters. In partnership with CleanBC, rebates of up to $11,000 are also available – when combined with the federal Greener Homes program – for those switching from fossil fuel heating to an electric heat pump.

'Heat dome' pushes summer highs to 40°C
Cooling wasn't really a consideration for Dexter and Cheryl when they were living in a smaller bungalow shaded by trees. But they knew that with the big windows, vaulted ceiling in the living room, and an upstairs bedroom in the new home, there may come a time when they needed air conditioning.

That day arrived shortly after the home was built, as the infamous "heat dome" settled on B.C. and drove temperatures at Fort St. James to a dizzying 40°C.

"It was disgustingly hot, and I don't care if I never see that again here," says Hodder, with a laugh. "But the heat pump maintained the house really nicely throughout, at about 22 degrees. The whole house stayed cool. We just had to close the door to the upper bedroom so it wasn't really heating up during the day."

Hodder says he had to work with the heat pump manufacturer Mitsubishi a couple times over that first year to fix a few issues with the system's controls. But he's confident that the building's tight and well-insulated envelope, and the heat pump's backup electric heat that kicks in when temperatures dip below -28°C, will make it the system-for-all-seasons it was designed to be.

Even with the use of supplemental electric heating during the record chill of December-January, the home's energy costs weren't much higher than the mid-winter energy bills they used to pay in the couple's smaller bungalow that relied on a combination of gas-fired in-floor heating and electric baseboards, as gas-for-electricity swaps are being explored elsewhere.

Fort St. James is a former fur trading post located northwest of Prince George and a short drive north of Vanderhoof. Winters are cold and snowy, with average daily low temperatures in December and January of around -14°C.

"During the summer and into the fall, we were paying well less than $100 a month," says Hodder, looking back at electricity bills over the first year in the home. "And that's everything. We're only electric here, and we also had both of us working from home all last year."

Word of mouth making heat pumps popular in Fort St. James
While the size of the home presented new challenges for the builders, it's one of five Net Zero Ready or Net Zero homes – all equipped with some form of heat pump – that Northern Homecraft has built in Fort St. James, even as debates about going nuclear for electricity continue in B.C.

The smallest of the homes is a two-bedroom, one-bathroom home that's just under 900 square feet. Northern Homecraft may be based in Vanderhoof, but it's the much smaller town of Fort St. James where they're making their mark with super-efficient homes. Net Zero Ready homes are up to 80% more efficient than the standard building code, and become Net Zero once renewable energy generation – usually in the form of photovoltaic solar – is installed, and programs like switching 5,000 homes to geothermal show the broader momentum for clean heating.

"We were pretty proud that the first home we built in Fort St. James was the first single family Net Zero Ready home built in B.C.," says Northern Homecraft's Bulmer. "And I think it's kind of caught on in a smaller community where everyone talks to everyone."

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UK Clean Electricity Record as wind, solar, and biomass boost renewable energy output, slashing carbon emissions and wholesale power prices during lockdown, while lower demand challenges grid balancing and drives a drop to 153 g/kWh.

Key Points

A milestone where wind, solar and biomass lifted renewables, cutting carbon intensity to 153 g/kWh during lockdown.

✅ Carbon intensity averaged 153 g/kWh in Q2 2020.

✅ Renewables output rose 32% via wind, solar, biomass.

✅ Wholesale power prices slumped 42% amid lower demand.

U.K electricity has never been cleaner. As wind, solar and biomass plants produced more power than ever in the second quarter, with a new wind generation record set, carbon emissions fell by a third from a year earlier, according to Drax Electric Insight’s quarterly report. Power prices slumped 42 per cent as demand plunged during lockdown. Total renewable energy output jumped 32 per cent in the period, as wind became the main source of electricity at times.

“The past few months have given the country a glimpse into the future for our power system, with higher levels of renewable energy, as wind led the power mix, and lower demand making for a difficult balancing act,”said  Iain Staffell, from Imperial College London and lead author of the report.

The findings of the report point to the impact energy efficiency can have on reducing emissions, as coal's share fell to record lows across the electricity system. Millions of people furloughed or working from home and shuttered shops up and down the country resulted in daily electricity demand dropping about 10% and being about four gigawatts lower than expected in the three months through June.

Average carbon emissions fell to a new low of 153 grams per kWh of electricity consumed over the quarter, as coal-free generation records were extended, even though low-carbon generation stalled in 2019, according to the report.

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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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