UK to fast-track vital grid connections

BC EV Charging Network Funding accelerates CleanBC goals with new public fast-charging stations, supporting ZEV adoption, the Electric Highway, and rebates, lowering fuel costs and emissions across British Columbia under the Clean Transportation Action Plan.

Key Points

Funding to expand fast-charging stations, grow ZEV adoption, and advance CleanBC and the Electric Highway.

✅ $26M funds ~250 public fast-charging stations.

✅ Supports Electric Highway and remote access.

✅ Drives ZEV sales under CleanBC targets.

As British Columbians are embracing zero-emission vehicles faster than any other jurisdiction in Canada, the Province is helping them go electric with new incentives and $26 million in new funding for public charging stations.

“British Columbians are switching to clean energy and cleaner transportation in record numbers as part of our CleanBC plan and leading Canada in the transition to zero emission vehicles,” said Josie Osborne, Minister of Energy, Mines and Low Carbon Innovation, on Tuesday. “The new funding we are announcing today to expand B.C.’s public charging network will help get more EVs on the road, reduce our reliance on fossil fuels, and lower fuel costs for people.”

The Province’s newly released annual report about zero-emission vehicles (ZEV) shows they represented 18.1% of new light-duty passenger vehicles sold in 2022 – the highest percentage for any province or territory. To support British Columbians’ transition to electric vehicles and to help industry lower its emissions, year-end funding of $26 million will go toward the CleanBC Public Charging Program for light-duty vehicle charging.

The new funding will support approximately 250 more public light-duty fast-charging stations, including stations to complete the B.C. Electric Highway, a CleanBC Roadmap to 2030 commitment that will make recharging easier in every corner of the province.

The 2022 ZEV Update report highlights CleanBC Go Electric rebates and programs that have helped drive growth in the number of electric vehicles in B.C. The number of registered light-duty EVs rose from 5,000 in 2016 to more than 100,000 today – a 1,900% increase in the past six years. Last year, 30,004 zero-emission vehicles were bought in B.C., beating the previous record of 24,263 in 2021.

In addition, the report outlines progress in the installation of public charging stations across British Columbia, supported by B.C. Hydro expansion, which now has one of the largest public charging networks in Canada, with more than 3,800 charging stations at the end of 2022. That compares to just 781 charging stations in 2016.

The CleanBC Roadmap to 2030, released in 2021, details a range of expanded actions to accelerate the switch to cleaner transportation, including strengthening the Zero-Emission Vehicles Act to require 26% of light-duty vehicle sales to be ZEV by 2026, 90% by 2030 and 100% by 2035 – five years ahead of the original target, and implementing the Clean Transportation Action Plan.

George Heyman, Minister of Environment and Climate Change Strategy, said: “Transportation accounts for about 40% of emissions in B.C., which is why we are committed to accelerating requirements for ZEVs and setting new standards for medium- and heavy-duty vehicles. To support this uptake, we continue to expand B.C.’s electric vehicle charging network, including faster EV charging options, with a target of having 10,000 public EV charging stations by 2030.”

Blair Qualey, President and CEO, New Car Dealers Association of BC, said: “B.C.’s new car dealers are proud to be involved in a true partnership that has been so instrumental in B.C. establishing and maintaining a leadership position in zero-emission vehicle adoption. Ongoing investments that continue to support the CleanBC Go Electric rebate program, including home and workplace charging rebates, and the availability of adequate charging infrastructure for consumers and businesses will be critical to the Province meeting its ZEV mandate targets, while also creating the promise of a greener and stronger economic future for British Columbians.”

Harry Constantine, President, Vancouver Electric Vehicle Association, said: “Expanding the buildout of the Electric Highway and establishing a network of charging stations are critical steps for moving the adoption of electric vehicles forward as demand ramps up across B.C. This stands to benefit all British Columbians, including remote communities. We are very pleased to see the Province investing in these measures.”

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North Sea Offshore Wind Farms will deliver 150 GW by 2050 as EU partners scale renewable energy, offshore turbines, grid interconnectors, and REPowerEU goals to cut emissions, boost energy security, and reduce Russian fossil dependence.

Key Points

A joint EU initiative to build 150 GW of offshore wind by 2050, advancing REPowerEU, decarbonization, and energy security.

✅ Targets at least 150 GW of offshore wind by 2050

✅ Backed by Belgium, Netherlands, Germany, and Denmark

✅ Aligns with REPowerEU, grid integration, and emissions cuts

Four European Union countries plan to build North Sea wind farms capable of producing at least 150 gigawatts of energy by 2050 to help cut carbon emissions that cause climate change, with EU wind and solar surpassing gas last year, Danish media have reported.

Under the plan, wind turbines would be raised off the coasts of Belgium, the Netherlands, Germany and Denmark, where a recent green power record highlighted strong winds, daily Danish newspaper Jyllands-Posten said.

The project would mean a tenfold increase in the EU's current offshore wind capacity, underscoring how renewables are crowding out gas across Europe today.

“The North Sea can do a lot," Danish Prime Minister Frederiksen told the newspaper, adding the close cooperation between the four EU nations "must start now.”

European Commission President Ursula von der Leyen, German Chancellor Olaf Scholz, Dutch Prime Minister Mark Rutte and Belgian Prime Minister Alexander De Croo are scheduled to attend a North Sea Summit on Wednesday in Esbjerg, 260 kilometers (162 miles) west of Copenhagen.

In Brussels, the European Commission moved Wednesday to jump-start plans for the whole 27-nation EU to abandon Russian energy amid the Kremlin’s war in Ukraine. The commission proposed a nearly 300 billion-euro ($315 billion) package that includes more efficient use of fuels and a faster rollout of renewable power, even as stunted hydro and nuclear output may hobble recovery efforts.

The investment initiative by the EU's executive arm is meant to help the bloc start weaning themselves off Russian fossil fuels this year, even as Europe is losing nuclear power during the transition. The goal is to deprive Russia, the EU’s main supplier of oil, natural gas and coal, of tens of billions in revenue and strengthen EU climate policies.

“We are taking our ambition to yet another level to make sure that we become independent from Russian fossil fuels as quickly as possible,” von der Leyen said in Brussels when announcing the package, dubbed REPowerEU.

The EU has pledged to reduce carbon dioxide emissions by 55% compared with 1990 levels by 2030, and to get to net zero emissions by 2050, with a recent German renewables milestone underscoring the pace of change.

The European Commission has set an overall target of generating 300 gigawatts of offshore energy of by 2050, though grid expansion challenges in Germany highlight hurdles.

Along with climate change, the war in Ukraine has made EU nations eager to reduce their dependency on Russian natural gas and oil. In 2021, the EU imported roughly 40% of its gas and 25% of its oil from Russia.

At a March 11 summit, EU leaders agreed in principle to phase out Russian gas, oil and coal imports by 2027.

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Harbour Air Electric Aircraft Project advances zero-emission aviation with CleanBC Go Electric ARC funding, converting seaplanes to battery-electric power, cutting emissions, enabling commercial passenger service, and creating skilled clean-tech jobs through R&D and electrification.

Key Points

Harbour Air's project electrifies seaplanes with CleanBC ARC support to enable zero-emission flights and cut emissions.

✅ $1.6M CleanBC ARC funds seaplane electrification retrofit

✅ Target: passenger-ready, zero-emission commercial service

✅ Creates 21 full-time clean-tech jobs in British Columbia

B.C.’s Harbour Air Seaplanes is building on its work in clean technology to decarbonize aviation, part of an aviation revolution underway, and create new jobs with support from the CleanBC Go Electric Advanced Research and Commercialization (ARC) program.

”Harbour Air is decarbonizing aviation and elevating the company to new altitudes as a clean-technology leader in B.C.'s transportation sector,” said Bruce Ralston, Minister of Energy, Mines and Low Carbon Innovation. “With support from our CleanBC Go Electric ARC program, Harbour Air's project not only supports our emission-reduction goals, but also creates good-paying clean-tech jobs, exemplifying the opportunities in the low-carbon economy.”

Harbour Air is receiving almost $1.6 million from the CleanBC Go Electric ARC program for its aircraft electrification project. The funding supports Harbour Air’s conversion of an existing aircraft to be fully electric-powered and builds on its successful December 2019 flight of the world’s first all-electric commercial aircraft, and subsequent first point-to-point electric flight milestones.

That flight marked the start of the third era in aviation: the electric age. Harbour Air is working on a new design of the electric motor installation and battery systems to gain efficiencies that will allow carrying commercial passengers, as it eyes first electric passenger flights in 2023. Approximately 21 full-time jobs will be created and sustained by the project.

“CleanBC is helping accelerate world-leading clean technology and innovation at Harbour Air that supports good jobs for people in our communities,” said George Heyman, Minister of Environment and Climate Change Strategy. “Once proven, the technology supports a switch from fossil fuels to advanced electric technology, and will provide a clean transportation option, such as electric ferries, that reduces pollution and shows the way forward for others in the sector.”

Harbour Air is a leader in clean-technology adoption. The company has also purchased a fully electric, zero-emission passenger shuttle bus to pick up and drop off passengers between Harbour Air’s downtown Vancouver and Richmond locations, and the Vancouver International Airport, where new EV chargers support travellers.

“It is great to see the Province stepping up to support innovation,” said Greg McDougall, Harbour Air CEO and ePlane test pilot. “This type of funding confirms the importance of encouraging companies in all sectors to focus on what they can be doing to look at more sustainable practices. We will use these resources to continue to develop and lead the transportation industry around the world in all-electric aviation.”

In total, $8.18 million is being distributed to 18 projects from the second round of CleanBC Go Electric ARC program funding. Recipients include Damon Motors and IRDI System, both based on the Lower Mainland. The 15 other successful projects will be announced this year.

The CleanBC Go Electric ARC program supports the electric vehicle (EV) sector in B.C., which leads the country in going electric, by providing reliable and targeted support for research and development, commercialization and demonstration of B.C.-based EV technologies, services and products.

“This project is a great example of the type of leading-edge innovation and tech advancements happening in our province,” said Brenda Bailey, Parliamentary Secretary for Technology and Innovation. “By further supporting the development of the first all-electric commercial aircraft, we are solidifying our position as world leaders in innovation and using technology to change what is possible.”

The CleanBC Roadmap to 2030 is B.C.’s plan to expand and accelerate climate action, including a major hydrogen project, building on the province’s natural advantages – abundant, clean electricity, high-value natural resources and a highly skilled workforce. It sets a path for increased collaboration to build a British Columbia that works for everyone.

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California NEM-3 Tariff ushers a successor Net Energy Metering framework, revising export compensation, TOU rates, and non-bypassable charges to balance ratepayer impacts, rooftop solar growth, and energy storage adoption across diverse communities.

Key Points

The CPUC's successor NEM policy redefining export credits and rates to sustain customer-sited solar and storage.

✅ Sets export compensation methodology beyond NEM 2.0

✅ Aligns TOU rates and non-bypassable charges with costs

✅ Encourages solar-plus-storage adoption and equity access

The California Public Utilities Commission (CPUC) has officially commenced its “NEM-3” proceeding, which will establish the successor Net Energy Metering (NEM) tariff to the “NEM 2.0” program in California. This is a highly anticipated, high-stakes proceeding that will effectively modify the rules for the NEM tariff in California, amid ongoing electricity pricing changes that affect residential rooftop solar – arguably the single most important policy mechanism for customer-sited solar over the last decade.

The CPUC’s recent order instituting rule-making (OIR) filing stated that “the major focus of this proceeding will be on the development of a successor to existing NEM 2.0 tariffs. This successor will be a mechanism for providing customer-generators with credit or compensation for electricity generated by their renewable facilities that a) balances the costs and benefits of the renewable electrical generation facility and b) allows customer-sited renewable generation to grow sustainably among different types of customers and throughout California’s diverse communities.”

This successor tariff proceeding was initiated by Assembly Bill 327, which was signed into law in October of 2013. AB 327 is best known as the legislation that directed the CPUC to create the “NEM 2.0” successor tariff, which was adopted by the CPUC in January of 2016.

The original Net Energy Metering program in California (“NEM 1.0”) effectively enabled full-retail value net metering “allowing NEM customers to be compensated for the electricity generated by an eligible customer-sited renewable resource and fed back to the utility over an entire billing period.” Under the NEM 2.0 tariff, customers were required to pay charges that aligned them more closely with non-NEM customer costs than under the original structure. The main changes adopted when the NEM 2.0 was implemented were that NEM 2.0 customer-generators must: (i) pay a one-time interconnection fee; (ii) pay non-bypassable charges on each kilowatt-hour of electricity they consume from the grid; and (iii) customers were required to transfer to a time-of-use (TOU) rate, with potential changes to electric bills for many customers.

NEM 2.0

The commencement of the NEM-3 OIR was preceded by the publishing of a 318-page Net Energy Metering 2.0 Lookback Study, which was published by Itron, Verdant Associates, and Energy and Environmental Economics. The CPUC-commissioned study had been widely anticipated and was expected to act as the starting reference point for the successor tariff proceeding. Verdant also hosted a webinar, which summarized the study’s inputs, assumptions, draft findings and results.

The study utilized several different tests to study the impact of NEM 2.0. The cost effectiveness analysis tests, which estimate costs and benefits attributed to NEM 2.0 include: (i) total resource cost test, (ii) participant cost test, (iii) ratepayer impact measure test, and (iv) program administrator test. The evaluation also included a cost of service analysis, which estimates the marginal cost borne by the utility to serve a NEM 2.0 customer.

The opening paragraph of the report’s executive summary stated that “overall, we found that NEM 2.0 participants benefit from the structure, while ratepayers see increased rates.” In every test that the author’s conducted the results generally supported this conclusion for residential customers. There were some exceptions in their findings. For example, in the cost of service analysis the report stated that “residential customers that install customer-sited renewable resources on average pay lower bills than the utility’s cost to serve them. On the other hand, nonresidential customers pay bills that are slightly higher than their cost of service after installing customer-sited renewable resources. This is largely due to nonresidential customer rates having demand charges (and other fixed fees), and the lower ratio of PV system size to customer load when compared to residential customers.”

Similar debates over solar rate design, including Massachusetts solar demand charges, highlight how demand charges and TOU decisions can affect customer economics.

NEM-3 timeline

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The preliminary schedule that the CPUC laid out in its OIR estimates that the proceeding will take roughly 15 months in total, starting with a November 2020 pre-hearing conference.

The real meat of the proceeding, where parties will present their proposals for what they believe the successor tariff should be, as the state considers revamping electricity rates to clean the grid, and really show their hand will not begin until the Spring of 2021. So we’re still a little ways away from seeing the proposals that the key parties to this proceeding, like the Investor Owned Utilities (PG&E, SCE, SDG&E), solar and storage advocates such as SEIA, CALSSA, Vote Solar, and ratepayer advocates like TURN) will submit.

While the outcome for the new successor NEM tariff is anyone’s guess at this point, some industry policy folks are starting to speculate. We think it is safe to assume that the value of exported energy will get reduced, with debates over income-based utility charges also influencing rate design. How much and the mechanism for how exports get valued remains to be seen. Based on the findings from the lookback study, it seems like the reduction in export value will be more severe than what happened when NEM 2.0 got implemented. In NEM 2.0, non-bypassable charges, which are volumetric charges that must be paid on all imported energy and cannot be netted-out by exports, only equated to roughly $0.02 to $0.03/kWh.

Given that the value of exports will almost certainly get reduced, we expect that to be bullish for energy storage as America goes electric and load shapes evolve. Energy storage attachment rates with solar are already steadily rising in California. By the time NEM-3 starts getting implemented, likely in 2022, we think storage attachment rates will likely escalate further.

We would not be surprised to see future storage attachment rates in California look like the Hawaiian market today, which are upwards of 80% for certain types of customers and applications. Two big questions on our mind are: (i) will the NEM 3.0 rules be different for different customer class: residential, CARE (e.g., low-income or disadvantaged communities), and commercial & industrial; (ii) will the CPUC introduce some sort of glidepath or phased in implementation approach?

The outcome of this proceeding will have far reaching implications on the future of customer-sited solar and energy storage in California. The NEM-3 outcome in California may likely serve as precedent for other states, as California exports its energy policies across the West, and utility territories that are expected to redesign their Net Energy Metering tariffs in the coming years.

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US Renewable Energy Capacity 2023 leads new utility-scale additions, with solar, wind, and battery storage surging; EIA data cite tax incentives, lower costs, and smart grid upgrades driving grid reliability and decarbonization.

Key Points

In 2023, renewables dominate new US utility-scale capacity: 54% solar, 7.1 GW wind, 8.6 GW battery storage, per EIA.

✅ 54% of 2023 US additions are solar, a record year

✅ 7.1 GW wind and 8.6 GW batteries expand grid resources

✅ Storage, smart grids, incentives boost reliability and growth

Wind, solar, and batteries make up 82% of 2023’s expected new utility-scale power capacity in the US, highlighting wind power's surge alongside solar and storage, according to the US Energy Information Administration’s (EIA) “Preliminary Monthly Electric Generator Inventory.”

As of January 2023, the US was operating 73.5 gigawatts (GW) of utility-scale solar capacity, which aligns with rising solar generation trends across the US – about 6% of the country’s total.

But solar makes up just over half of new US generating capacity expected to come online in 2023, supported by favourable government plans across key markets. And if it all goes as expected, it will be the most solar capacity added in a single year in the US. It will also be the first year that more than half of US capacity additions are solar, underscoring solar's No. 3 renewable ranking in the U.S. mix.

As of January 2023, 141.3 GW of wind capacity was operating in the US, reflecting wind's status as the most-used renewable nationwide – about 12% of the US total. Another 7.1 GW are planned for 2023. Tax incentives, lower wind turbine construction costs, and new renewable energy targets are spurring the growth. 

And developers also plan to add 8.6 GW of battery storage power capacity to the grid this year, supporting record solar and storage buildouts across the market, and that’s going to double total US battery power capacity.

However, differences in the amount of electricity that different types of power plants can produce mean that wind and solar made up about 17% of the US’s utility-scale capacity in 2021, but produced 12% of electricity, even as renewables surpassed coal nationally in 2022. Solutions such as energy storage, smart grids, and infrastructure development will help bridge that gap.

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Electric Fleet Grid Planning aligns utilities, charging infrastructure, distribution upgrades, and substation capacity to meet megawatt loads from medium- and heavy-duty EV trucks and buses, enabling managed charging, storage, and corridor fast charging.

Key Points

A utility plan to upgrade feeders and substations for EV fleets, coordinating charging, storage, and load management.

✅ Plans distribution, substation, and transformer upgrades

✅ Supports managed charging and on-site storage

✅ Aligns utility investment with fleet adoption timelines

As more electric buses and trucks enter the market, future fleets will require a lot of electricity for charging and will challenge state power grids over time. While some utilities in California and elsewhere are planning for an increase in power demand, many have yet to do so and need to get started.

This issue is critical, because freight trucks emit more than one-quarter of all vehicle emissions. Recent product developments offer growing opportunities to electrify trucks and buses and slash their emissions (see our recent white paper). And just last week, a group of 15 states plus D.C. announced plans to fully electrify truck sales by 2050. Utilities will need to be ready to power electric fleets.

Electric truck fleets need substantial power
Power for trucks and buses is generally more of an issue than for cars because trucks typically have larger batteries and because trucks and buses are often parts of fleets with many vehicles that charge at the same location. For example, a Tesla Model 3 battery stores 54-75 kWh; a Proterra transit bus battery stores 220-660 kWh. In Amsterdam, a 100-bus transit fleet is powered by a set of slow and fast chargers that together have a peak load of 13 MW (megawatts). This is equivalent to the power used by a typical large factory. And they are thinking of expanding the fleet to 250 buses.

California utilities are finding that grid capacity is often adequate in the short term, but that upgrade needs likely will grow in the medium term.
Many other fleets also will need a lot of "juice." For example, a rough estimate of the power needed to serve a fleet of 200 delivery vans at an Amazon fulfillment center is about 4 MW. And for electric 18-wheelers, chargers may need up to 2 MW of power each; a recent proposal calls for charging stations every 100 miles along the U.S. West Coast’s I-5 corridor, highlighting concerns about EVs and the grid as each site targets a peak load of 23.5 MW.

Utilities need distribution planning
These examples show the need for more power at a given site than most utilities can provide without planning and investment. Meeting these needs often will require changes to primary and secondary power distribution systems (feeders that deliver power to distribution transformers and to end customers) and substation upgrades. For large loads, a new substation may be needed. A paper recently released by the California Electric Transportation Coalition estimates that for loads over 5 MW, distribution system and substation upgrades will be needed most of the time. According to the paper, typical utility costs are $1 million to $9 million for substation upgrades, $150,000 to $6 million for primary distribution upgrades, and $5,000 to $100,000 for secondary distribution upgrades. Similarly, Black and Veatch, in a paper on Electric Fleets, also provides some general guidance, shown in the table below, while recognizing that each site is unique.

California policy pushes utilities toward planning
In California, state agencies and a statewide effort called CALSTART have been funding demonstration projects and vehicle and charger purchases for several years to support grid stability as electrification ramps up. The California Air Resources Board voted in June to phase in zero-emission requirements for truck sales, mandating that, beginning in 2024, manufacturers must increase their zero-emission truck sales to 30-50 percent by 2030 and 40-75 percent by 2035. By 2035, more than 300,000 trucks will be zero-emission vehicles.

California utilities operate programs that work with fleet owners to install the necessary infrastructure for electric vehicle fleets. For example, Southern California Edison operates the Charge Ready Transport program for medium- and heavy-duty fleets. Normally, when customers request new or upgraded service from the utility, there are fees associated with the new upgrade. With Charge Ready, the utility generally pays these costs, and it will sometimes pay half the cost of chargers; the customer is responsible for the other half and for charger installation costs. Sites with at least two electric vehicles are eligible, but program managers report that at least five vehicles are often needed for the economics to make sense for the utility.

One way to do this is to develop and implement a phased plan, with some components sized for future planned growth and other components added as needed. Southern California Edison, for example, has 24 commitments so far, and has a five-year goal of 870 sites, with an average of 10 chargers per site. The utility notes that one charger usually can serve several vehicles and that cycling of charging, some storage, and other load management techniques through better grid coordination can reduce capacity needs (a nominal 10 MW load often can be reduced below 5 MW).

Through this program, utility representatives are regularly talking with fleet operators, and they can use these discussions to help identify needed upgrades to the utility grid. For example, California transit agencies are doing the planning to meet a California Air Resources Board mandate for 100 percent electric or fuel cell buses by 2040; utilities are talking with the agencies and their consultants as part of this process. California utilities are finding that grid capacity is often adequate in the short term, but that upgrade needs likely will grow in the medium term (seven to 10 years out). They can manage grid needs with good planning (school buses generally can be charged overnight and don’t need fast chargers), load management techniques and some energy storage to address peak needs.

Customer conversations drive planning elsewhere
We also spoke with a northeastern utility (wishing to be unnamed) that has been talking with customers about many issues, including fleets. It has used these discussions to identify a few areas where grid upgrades might be needed if fleets electrify. It is factoring these findings into a broader grid-planning effort underway that is driven by multiple needs, including fleets. Even within an integrated planning effort, this utility is struggling with the question of when to take action to prepare the electric system for fleet electrification: Should it act on state or federal policy? Should it act when the specific customer request is submitted, or is there something in between? Recognizing that any option has scheduling and cost allocation implications, it notes that there are no easy answers.

Many utilities need to start paying attention
As part of our research, we also talked with several other utilities and found that they have not yet looked at how fleets might relate to grid planning. However, several of these companies are developing plans to look into these issues in the next year. We also talked with a major truck manufacturer, also wishing to remain unnamed, that views grid limitations as a key obstacle to truck electrification. 

Based on these cases, it appears that fleet electrification can have a substantial impact on electric grids and that, while these impacts are small at present, they likely will grow over time. Fleet owners, electric utilities, and utility regulators need to start planning for these impacts now, so that grid improvements can be made steadily as electric fleets grow. Fleet and grid planning should happen in parallel, so that grid upgrades do not happen sooner or later than needed but are in place when needed, including the move toward a much bigger grid as EV adoption accelerates. These grid impacts can be managed and planned for, but the time to begin this planning is now.

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