Peak Power Receives $765,000 From Canadian Government to Deploy 117 V1G EV Chargers

Space-Based Solar Power enables wireless energy transfer from orbital solar arrays, using microwave beaming to rectennas on Earth, delivering clean baseload power beyond weather and night limits, as demonstrated by Caltech and NASA.

Key Points

Space-based solar power beams microwaves from arrays to rectennas, delivering clean electricity beyond weather and night.

✅ Caltech demo proved wireless power transfer in space.

✅ Microwaves beam to rectennas for grid-scale clean energy.

✅ Operates above clouds, enabling continuous baseload supply.

Ali Hajimiri thinks there’s a better way to power the planet — one that’s not getting the attention it deserves. The Caltech professor of electrical engineering envisages thousands of solar panels floating in space, unobstructed by clouds and unhindered by day-night cycles, effectively generating electricity from the night sky for continuous delivery, wirelessly transmitting massive amounts of energy to receivers on Earth.

This year, that vision moved closer to reality when Mr. Hajimiri, together with a team of Caltech researchers, proved that wireless power transfer in space was possible: Solar panels they had attached to a Caltech prototype in space successfully converted electricity into microwaves and beamed those microwaves to receivers, as a demonstration of beaming power from space to devices about a foot away, lighting up two LEDs.

The prototype also beamed a tiny but detectable amount of energy to a receiver on top of their lab’s building in Pasadena, Calif. The demonstration marks a first step in the wireless transfer of usable power from space to Earth, and advances in low-cost solar batteries could help store and smooth that power flow — a power source that Mr. Hajimiri believes will be safer than direct sun rays. “The beam intensity is to be kept less than solar intensity on earth,” he said.

Finding alternative energy sources is one of the topics that will be discussed by leaders in business, science and public policy, including wave energy, during The New York Times Climate Forward event on Thursday. The Caltech demonstration was a significant moment in the quest to realize space-based solar power, amid policy moves such as a proposed tenfold increase in U.S. solar that would remake the U.S. electricity system — a clean energy technology that has long been overshadowed by other long-shot clean energy ideas, such as nuclear fusion and low-cost clean hydrogen.

If space-based solar can be made to work on a commercial scale, said Nikolai Joseph, a NASA Goddard Space Flight Center senior technology analyst, and integrate with peer-to-peer energy sharing networks, such stations could contribute as much as 10 percent of global power by 2050.

The idea of space-based solar energy has been around since at least 1941, when the science-fiction writer Isaac Asimov set one of his short stories, “Reason,” on a solar station that beamed energy by microwaves to Earth and other planets.

In the 1970s, when a fivefold increase in oil prices sparked interest in alternative energy, NASA and the Department of Energy conducted the first significant study on the topic. In 1995, under the direction of the physicist John C. Mankins, NASA took another look and concluded that investments in space-launch technology were needed to lower the cost and move closer to cheap abundant electricity before space-based solar power could be realized.

“There was never any doubt about it being technically feasible,” said Mr. Mankins, now president of Artemis Innovation Management Solutions, a technology consulting group. “The cost was too prohibitive.”

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SEA Electric school bus conversions bring EV electrification to Type A and Type C fleets, adding V2G, smart charging, battery packs, and zero-emissions performance while extending service life with cost-effective retrofits across US school districts.

Key Points

Retrofit EV drivetrains for Type A and C buses, adding V2G and smart charging to cut emissions and costs.

✅ Converts 10,000 Type A and C school buses over five years

✅ Adds V2G, smart charging, and fleet battery management

✅ Cuts diesel fumes, maintenance, and total cost of ownership

Converting a Porsche 356C to electric power is a challenge. There’s precious little room for batteries, converters, and such. But converting a school bus? That’s as easy as falling off a log, even if adoption challenges persist in the sector today. A bus has acres of space for batteries and the electronics need to power an electric motor.

One of the dumbest ideas human beings ever came up with was sealing school children inside a diesel powered bus for the trip to and from school. Check out our recent article on the impact of fossil fuel pollution on the human body. Among other things, fine particulates in the exhaust gases of an internal combustion engine have been shown to lower cognitive function. Whose bright idea was it to make school kids walk through a cloud of diesel fumes twice a day when those same fumes make it harder for them to learn?

Help may be on the way, as lessons from the largest e-bus fleet offer guidance for scaling. SEA Electric, a provider of electric commercial vehicles originally from Australia and now based in Los Angeles has stuck a deal with Midwest Transit Equipment to convert 10,000 existing school buses to electric vehicles over the next five years. Midwest will provide the buses to be converted to the SEA Drive propulsion system. SEA Electric will complete the conversions using its “extensive network of up-fitting partners,” Nick Casas, vice president of sales and marketing for SEA Electric, says in a press release.

After the conversions are completed, the electric buses will have vehicle to grid (V2G) capability that will allow them to help balance the local electrical grid, where state power grids face new demands, and “smart charge” when electricity prices are lowest. The school buses to be converted are of the US school bus class Type A  or Type C. Type A is the smallest US school bus with a length of 6 to 7.5 metres and is based on a van chassis. The traditional Type C school buses are built on truck architectures.

SEA Electric says that the conversion will extend the life of the buses by more than ten years, with early deployments like B.C. electric school buses demonstrating real-world performance, and that two to three converted buses can be had for the price of one new electric bus. Mike Menyhart, chief strategy officer at SEA Electric says, “The secondary use of school buses fitted with all-electric drivetrains makes a lot of sense. It keeps costs down, opens up considerable availability, creates green jobs right here in the US, all while making a difference in the environment and the health of the communities we serve.”

According to John McKinney, CEO of Midwest Transport Equipment, the partnership with SEA Electric will ensure that it can respond more quickly to customers’ needs as policies like California's 2035 school-bus mandate accelerate demand in key markets. “As the industry moves towards zero emissions we are positioned well with our SEA Electric partnership to be a leader of the electrification movement.”

According to Nick Casas, SEA Electric will plans to expand it operations to the UK soon, and intends to do business in six countries in Europe, including Germany, in the years to come. SEA says it will have delivered more than 500 electric commercial vehicles in 2021 and plans to put more than 15,000 electric vehicles on the road by the end of 2023. Just a few weeks ago, SEA Electric announced an order for 1,150 electric trucks based on the Toyota Hino cargo van for the GATR company of California, highlighting truck fleet power needs that utilities must plan for today.

Electric school buses make so much sense. No fumes to fog young brains, lower maintenance costs, and lower fuel costs are all pluses, especially as bus depot charging hubs scale across markets, adding resilience. Extending the service life of an existing bus by a decade will obviously pay big dividends for school bus fleet operators like MTE. It’s a win/win/win situation for all concerned, with the possible exception of diesel mechanics. But the upside there is they can be retrained in how to maintain electric vehicles, a skill that will be in increasing demand as the EV revolution picks up speed.

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Canada ZEV Availability Standard sets EV sales targets and zero-emission mandates, using compliance credits, early credits, and charging infrastructure investments under CEPA to accelerate affordable ZEV supply and meet 2035 net-zero goals.

Key Points

A federal ZEV policy setting 2026-2035 sales targets, using tradable credits and infrastructure incentives under CEPA.

✅ Applies to automakers; compliance via tradable ZEV credits under CEPA.

✅ Targets: 20% by 2026, 60% by 2030, 100% by 2035.

✅ Early credits up to 10% for 2026; charging investments earn credits.

Canadian Automobile manufacturers are on the brink of significant changes as Ottawa prepares to introduce its long-awaited electric vehicle regulations. A reliable source within the government says final regulations are aimed at ensuring that all new passenger vehicles sold in Canada by 2035 are zero-emission vehicles, a goal some critics question through analyses of the 2035 EV mandate in Canada.

These regulations, known as the Electric Vehicle Availability Standard, are designed to encourage automakers to produce more affordable zero-emission vehicles to meet the increasing demand. One of the key concerns for Canada is the potential dominance of zero-emission vehicle supply by other countries, particularly the United States, where several states have already implemented sales targets for such vehicles, and new EPA emission limits are expected to boost EV sales nationwide as well.

It's important to note that these regulations will apply primarily to automakers, rather than dealerships. Under this legislation, manufacturers will be required to accumulate sufficient credits to demonstrate their compliance with the established targets.

Automakers will be able to earn credits based on their sales of low- and no-emissions vehicles. The number of credits earned will depend on how close these vehicles come to meeting a zero-emissions standard. Additionally, manufacturers could earn early credits, amounting to a maximum of 10 percent of their total compliance requirements for 2026, by introducing more electric vehicles to the market ahead of schedule, even amid recent EV shortages and wait times reported across Canada.

Automakers can also increase their credit balance by contributing to the development of electric vehicle charging infrastructure, recognizing that fossil fuels still powered part of Canada's grid in 2019 and that charging availability remains a key enabler. In cases where companies exceed or fall short of their compliance targets, they will have the option to buy or sell credits to other manufacturers or use previously accumulated credits.

Further details regarding these regulations, which will be enacted under the Canadian Environmental Protection Act, are set to be unveiled soon and will intersect with provincial approaches such as Quebec's, where experts have questioned the push for EV dominance as policies evolve.

These regulations will become effective starting with the model year 2026, and sales targets will progressively rise each year until 2035. The federal government's ambitious EV goals are to have 20 percent of all vehicles sold in Canada be zero-emission vehicles by 2026, with that figure increasing to 60 percent by 2030 and reaching 100 percent by 2035.

According to a government analysis conducted in 2022, the anticipated total cost to consumers for zero-emission vehicles and chargers over 25 years is estimated at $24.5 billion, though cost remains a primary barrier for many Canadians considering an EV. However, it is projected that Canadians will save approximately $33.9 billion in net energy costs over the same period. Please note that these estimates are part of a draft and may be subject to change upon the government's release of its final analysis.

In terms of environmental impact, these regulations are expected to prevent the release of an estimated 430 million tonnes of greenhouse gas emissions, according to regulatory analysis. Environmental Defence, a Canadian environmental think-tank, has estimated that the policy would also result in a substantial reduction in gasoline consumption, equivalent to filling approximately 73,000 Olympic-sized swimming pools with gasoline.

Nate Wallace, the program manager for clean transportation at Environmental Defence, emphasized the significance of these regulations, stating, "2035 really needs to be the last year that we are selling gasoline cars in Canada brand new if we're going to have any chance of actually, by 2050, reaching net-zero carbon emissions."

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U.S. Solar-Plus-Storage Growth 2021-2024 highlights rising battery storage co-location with solar PV, grid flexibility, RTO/ISO market signals, and ITC incentives, enabling peak shaving, firming renewable output, and reliable night-time power.

Key Points

Summary of U.S. plans pairing battery storage with solar PV, guided by RTO/ISO markets, grid needs, and ITC policy.

✅ 9.4 GW (63%) co-located with solar PV by 2024

✅ 97% of standalone capacity sited in RTO/ISO regions

✅ ITC improves project economics and grid services revenue

Of the 14.5 gigawatts (GW) of battery storage power capacity planned to come online amid anticipated growth in solar and storage in the United States from 2021 to 2024, 9.4 GW (63%) will be co-located with a solar photovoltaic (PV) solar-plus-storage power plant, based on data reported to us and published in our Annual Electric Generator Report. Another 1.3 GW of battery storage will be co-located at sites with wind turbines or fossil fuel-fired generators, such as natural gas-fired plants. The remaining 4.0 GW of planned battery storage will be located at standalone sites.

Historically, most U.S. battery systems have been located at standalone sites. Of the 1.5 GW of operating battery storage capacity in the United States at the end of 2020, 71% was standalone, and 29% was located onsite with other power generators.

Most standalone battery energy storage sites have been planned or built in power markets that are governed by regional transmission organizations (RTOs) and independent system operators (ISOs). RTOs and ISOs can enforce standard market rules that lay out clear revenue streams for energy storage projects in their regions, which promotes the deployment of battery storage systems. Of the utility-scale pipeline battery systems announced to come online from 2021 to 2024, 97% of the standalone battery capacity and 60% of the co-located battery capacity are in RTO/ISO regions.

Over 90% of the planned battery storage capacity outside of RTO and ISO regions will be co-located with a solar PV plant. At some solar PV co-located plants, the batteries can charge directly from the onsite solar generator when electricity demand and prices are low. They can then discharge electricity to the grid when peak demand is higher or when solar generation is unavailable, such as at night.

Although factors such as cloud cover can affect solar generation output, solar generators, now the number three renewable source in the U.S., in particular can effectively pair with battery storage because of their relatively regular daily generation patterns. This predictability works well with battery systems because battery systems are limited in how long they can discharge their power capacity before needing to recharge. If paired with a wind turbine, for example, a battery system could go days before having the opportunity to fully recharge.

Another advantage of pairing batteries with renewable generators is the ability to take advantage of tax incentives such as the Investment Tax Credit (ITC), which is available for solar projects, and other favorable government plans supporting deployment.

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Nova Scotia Biomass Electricity Policy increases dispatchable renewable generation from Port Hawkesbury and Brooklyn Energy, raising MWh output while critics cite clearcutting, carbon emissions, high costs to ratepayers, and delays replacing Muskrat Falls hydro.

Key Points

Policy directing utilities to maximize biomass power as dispatchable renewable supply during hydro delays.

✅ Port Hawkesbury biomass output up 35% year over year

✅ Brooklyn Energy used as dispatchable renewable supply

✅ Critics cite clearcutting, emissions, high ratepayer costs

A boiler owned by Nova Scotia Power on the grounds of the Port Hawkesbury paper plant, whose discount power rate request has drawn attention, is burning 35% more woody biomass this year than last. 

The year-to-date figures show 126,810 megawatt hours (MWh) of electricity was generated over the first nine months of 2021 compared to 93,934 MWh for the same period in 2020 and 65,891 MWh in 2019. 

The information is contained in monthly fuel cost reports Nova Scotia Power must make to the Utility and Review Board, which regulates how much consumers ultimately pay for electricity and has received a call for major grid changes in Nova Scotia.

Burning biomass  — which includes everything from low-grade pulpwood to bark, shavings, and wood chip waste from sawmills — for the purpose of generating electricity is only about 22% efficient, even as some coal stations have switched to biomass abroad. Nova Scotia Power’s boiler at Port Hawkesbury supplies about 3% of the total electricity used in the province. 

Citizens concerned about climate change have for years opposed the government classifying biomass as “renewable energy” and have echoed calls to reduce biomass use for electricity, because clearcutting, which releases carbon from the ground, remains the dominant form of harvesting on Crown and private land. That’s despite ongoing work to begin implementing 2018 recommendations from Professor Bill Lahey to move toward a more ecological approach. 

In May 2020, after it became obvious renewable hydroelectricity from Muskrat Falls was going to be delayed yet again, the McNeil government passed an Order-in-Council extending until December 2022 the deadline to generate 40% of electricity from renewable sources as it moved to increase wind and solar projects across Nova Scotia. 

To help with the shortfall, Nova Scotia Power was told to “maximize” its use of biomass at both the facility it owns in Port Hawkesbury and another one in Brooklyn owned by its parent company, Emera.

In a letter to Nova Scotia Power dated May 15, then-Energy Minister Derek Mombourquette, amid debate over independent energy planning, added: “Nova Scotia Power shall also maximize the use of dispatchable renewable electricity from its own facilities, as well as those of renewable electricity power producers in Nova Scotia (excluding COMFIT generation sources).” 

By definition, “dispatchable” excludes wind and hydro sources, which are not available 24/7, though a new attempt to harness the Bay of Fundy's tides is underway. Nova Scotia Power claims the only “dispatchable renewable electricity power producer” in the province is Brooklyn Energy, the 35 MW biomass plant near Liverpool. 

The government capped at $7 million a year how much electricity Nova Scotia Power could buy from its affiliate company. Critics of the deal — such as auditors hired by the regulator and the province’s consumer advocate — say electricity generated by Brooklyn is the most expensive power and question why the province would burden ratepayers with its purchase.

The answer became apparent in September 2020 when then-Intergovernmental Affairs Minister Kelliann Dean appeared before the legislature’s standing committee on Natural Resources and Economic Development to praise the Order-in-Council for helping rescue the forestry industry four months after the closure of the Northern Pulp mill. 

“The change to Renewable Energy Standards (May,2020) is enabling Nova Scotia Power to generate more electricity from wood chips and sawmill residuals by operating two biomass plants at capacity until electricity from Muskrat Falls comes onstream,” she said. “We are using all the policy levers at our disposal to support the sector.”

Nova Scotia Power is not required to report to the UARB how much electricity is being produced or how much biomass is being burned at Brooklyn Energy. The company pleads “commercial confidentiality” when asked by The Halifax Examiner. 

Nova Scotia Power does report how much it spends each month to buy power from independent producers — a small group which includes Brooklyn but excludes all wind farms. That dollar amount has also increased over the past year — from $15.9 million for 10 months ending October 2020 compared to $23.3 million for 10 months ending October 2021. Unfortunately, the lack of transparency makes it impossible to know exactly how much of that increase is attributable to purchasing more biomass.

Radio silence
The current Minister of Natural Resources and Renewable Energy ,Tory Rushton, has the authority to reduce the amount of biomass being burned to generate electricity and by extension, the rate of clearcutting.

With a stroke of the pen, the PC government of Tim Houston could issue another Order-in-Council capping the amount of metric tonnes that could be used in the boilers, or, direct Nova Scotia Power to use biomass only when it is the most economical fuel choice. 

But so far, Rushton has not responded to the Halifax Examiner’s question about whether he intends to make any change to stop “maximizing” the use of biomass to produce electricity.

 The Examiner isn’t the only one pushing the Minister for answers to difficult issues. At noon today, Citizens opposed to a controversial clearcut on Crown land near Rocky Point Lake in Digby County will stage a demonstration outside the Department of Natural Resources and Renewable Energy on Hollis Street. The protest led by members of Extinction Rebellion and the Healthy Forest Coalition is to pressure the government to take action to protect the habitat of the mainland moose, an endangered species that ranges overs the Crown land currently being cut by the Westfor consortium. 

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EVI-Pro Lite EV Load Forecasting helps utilities model EV charging infrastructure, grid load shapes, and resilient energy systems, factoring home, workplace, and public charging behavior to inform planning, capacity upgrades, and flexible demand strategies.

Key Points

A NREL tool projecting EV charging demand and load shapes to help utilities plan the grid and right-size infrastructure.

✅ Visualizes weekday/weekend EV load by charger type.

✅ Tests home, workplace, and public charging access scenarios.

✅ Supports utility planning, demand flexibility, and capacity upgrades.

As electric vehicles (EVs) continue to grow in popularity, utilities and community planners are increasingly focused on building resilient energy systems that can support the added electric load from EV charging, including a possible EV-driven demand increase across the grid.

But forecasting the best ways to adapt to increased EV charging can be a difficult task as EV adoption will challenge state power grids in diverse ways. Planners need to consider when consumers charge, how fast they charge, and where they charge, among other factors.

To support that effort, researchers at the National Renewable Energy Laboratory (NREL) have expanded the Electric Vehicle Infrastructure Projection (EVI-Pro) Lite tool with more analytic capabilities. EVI-Pro Lite is a simplified version of EVI-Pro, the more complex, original version of the tool developed by NREL and the California Energy Commission to inform detailed infrastructure requirements to support a growing EV fleet in California, where EVs bolster grid stability through coordinated planning.

EVI-Pro Lite’s estimated weekday electric load by charger type for El Paso, Texas, assuming a fleet of 10,000 plug-in electric vehicles, an average of 35 daily miles traveled, and 50% access to home charging, among other variables, as well as potential roles for vehicle-to-grid power in future scenarios. The order of the legend items matches the order of the series stacked in the chart.

Previously, the tool was limited to letting users estimate how many chargers and what kind of chargers a city, region, or state may need to support an influx of EVs. In the added online application, those same users can take it a step further to predict how that added EV charging will impact electricity demand, or load shapes, in their area at any given time and inform grid coordination for EV flexibility strategies.

“EV charging is going to look different across the country, depending on the prevalence of EVs, access to home charging, and the kind of chargers most used,” said Eric Wood, an NREL researcher who led model development. “Our expansion gives stakeholders—especially small- to medium-size electric utilities and co-ops—an easy way to analyze key factors for developing a flexible energy strategy that can respond to what’s happening on the ground.”

Tools to forecast EV loads have existed for some time, but Wood said that EVI-Pro Lite appeals to a wider audience, including planners tracking EVs' impact on utilities in many markets. The tool is a user-friendly, free online application that displays a clear graphic of daily projected electric loads from EV charging for regions across the country.

After selecting a U.S. metropolitan area and entering the number of EVs in the light-duty fleet, users can change a range of variables to see how they affect electricity demand on a typical weekday or weekend. Reducing access to home charging by half, for example, results in higher electric loads earlier in the day, although energy storage and mobile charging can help moderate peaks in some cases. That is because under such a scenario, EV owners might rely more on public or workplace charging instead of plugging in at home later in the evening or at night.

“Our goal with the lite version of EVI-Pro is to make estimating loads across thousands of scenarios fast and intuitive,” Wood said. “And if utilities or stakeholders want to take that analysis even deeper, our team at NREL can fill that gap through partnership agreements, too. The full version of EVI-Pro can be tailored to develop detailed studies for individual planners, agencies, or utilities.”

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