B.C. expands EV charging, leads country in going electric

Utility-Controlled EV Charging shapes who builds charging stations as utilities, regulators, and private networks compete over infrastructure, grid upgrades, and pricing, impacting ratepayers, competition, and EV adoption across states seeking cleaner transport.

Key Points

Utility-controlled EV charging is utilities building charging networks affecting rates, competition and grid costs.

✅ Regulated investment may raise rates before broader savings.

✅ Private firms warn monopolies stifle competition and innovation.

✅ Regulators balance access, equity, and grid upgrade needs.

Electric vehicles are widely seen as the automobile industry’s future, but a battle is unfolding in states across America over who should control the charging stations that could gradually replace fuel pumps.

From Exelon Corp. to Southern California Edison, utilities have sought regulatory approval to invest millions of dollars in upgrading their infrastructure as state power grids adapt to increased charging demand, and, in some cases, to own and operate chargers.

The proposals are sparking concerns from consumer advocates about higher electric rates and oil companies about subsidizing rivals. They are also drawing opposition from startups that say the successors to gas stations should be open to private-sector competition, not controlled by monopoly utilities.

That debate is playing out in regulatory commissions throughout the U.S. as states and utilities promote wider adoption of electric vehicles. At stake are charging infrastructure investments expected to total more than $13 billion over the next five years, as an American EV boom accelerates, according to energy consulting firm Wood Mackenzie. That would cover roughly 3.2 million charging outlets.

Calvin Butler Jr., who leads Exelon’s utilities business, said many states have grown more open to the idea of utilities becoming bigger players in charging as electric vehicles have struggled to take off in the U.S., where they make up only around 2% of new car sales.

“When the utilities are engaged, there’s quicker adoption because the infrastructure is there,” he said.

Major auto makers including General Motors Co. and Ford Motor Co. are accelerating production of electric vehicles, and models like Tesla’s Model 3 are shaping utility planning, and a number of states have set ambitious EV goals—most recently California, which aims to ban the sale of new gasoline-powered cars by 2035. But a patchy charging-station network remains a huge impediment to mass EV adoption.

Democratic presidential candidate Joe Biden has called for building more than 500,000 new public charging outlets in a decade as part of his plan to combat climate change, amid Biden’s push to electrify the transportation sector. But exactly how that would happen is unclear. The U.S. currently has fewer than 100,000 public outlets, according to the Energy Department. President Trump, who has weakened federal tailpipe emissions targets, hasn’t put forward an electric-vehicle charging plan, though he backed a 2019 transportation bill that would have provided $1 billion in grants to build alternative fueling infrastructure, including for electric vehicles.

Charging access currently varies widely by state, as does utility involvement, with many utilities bullish course on EV charging to support growth, which can range from providing rebates on home chargers to preparing sites for public charging—and even owning and operating the equipment needed to juice up electric vehicles.

As of September, regulators in 24 states had signed off on roughly $2.6 billion of utility investment in transportation electrification, according to Atlas Public Policy, a Washington, D.C., policy firm. More than half of that spending was authorized in California, where electric vehicle adoption is highest.

Nearly a decade ago, California blocked utilities from owning most charging equipment, citing concerns about potentially stifling competition. But the nation’s most populous state reversed course in 2014, seeking to spur electrification.

Regulators across the country have since been wrestling with similar questions, generating a patchwork of rules.

Maryland regulators signed off last year on a pilot program allowing subsidiaries of Exelon and FirstEnergy Corp. to own and operate public charging stations on government property, provided that the drivers who use them cover at least some of the costs.

Months later, the District of Columbia rejected an Exelon subsidiary’s request to own public chargers, saying independent charging companies had it covered.

Some charging firms argue utilities shouldn’t be given monopolies on car charging, though they might need to play a role in connecting rural customers and building stations where they would otherwise be uneconomical.

“Maybe the utility should be the supplier of last resort,” said Cathy Zoi, chief executive of charging network EVgo Services LLC, which operates more than 800 charging stations in 34 states.

Utility charging investments generally are expected to raise customers’ electricity bills, at least initially. California recently approved the largest charging program by a single utility to date: a $436 million initiative by Southern California Edison, an arm of Edison International, as the state also explores grid stability opportunities from EVs. The company said it expects the program to increase the average residential customer’s bill by around 50 cents a month.

But utilities and other advocates of electrification point to studies indicating greater EV adoption could help reduce electricity rates over time, by giving utilities more revenue to help cover system upgrades.

Proponents of having utilities build charging networks also argue that they have the scale to do so more quickly, which would lead to faster EV adoption and environmental improvements such as lower greenhouse gas emissions and cleaner air. While the investments most directly help EV owners, “they accrue immediate benefits for everyone,” said Jill Anderson, a Southern California Edison senior vice president.

Some consumer advocates are wary of approving extensive utility investment in charging, citing the cost to ratepayers.

“It’s like, ‘Pay me now, and maybe someday your rates will be less,’” said Stefanie Brand, who advocates on behalf of ratepayers for the state of New Jersey, where regulators have yet to sign off on any utility proposals to invest in electric vehicle charging. “I don’t think it makes sense to build it hoping that they will come.”

Groups representing oil-and-gas companies, which stand to lose market share as people embrace electric vehicles, also have criticized utility charging proposals.

“These utilities should not be able to use their monopoly power to use all of their customers’ resources to build investments that definitely won’t benefit everybody, and may or may not be economical at this point,” said Derrick Morgan, who leads federal and regulatory affairs at the American Fuel & Petrochemical Manufacturers, a trade organization.

Utility executives said their companies have long been used to further government policy objectives deemed to be in the public interest, drawing on lessons from 2021 to guide next steps, such as improving energy efficiency.

“This isn’t just about letting market forces work,” said Mike Calviou, senior vice president for strategy and regulation at National Grid PLC’s U.S. division.

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U.S. Solar Panel Shipments 2021 surged to 28.8 million kW of PV modules, tracking utility-scale and small-scale capacity additions, driven by imports from Asia, resilient demand, supply chain constraints, and declining prices.

Key Points

Record 28.8M kW PV modules shipped in 2021; 80% imports; growth in utility- and small-scale capacity with lower prices.

✅ 28.8M kW shipped, up from 21.8M kW in 2020 (record capacity)

✅ 80% of PV module shipments were imports, mainly from Asia

✅ Utility-scale +13.2 GW; small-scale +5.4 GW; residential led

U.S. shipments of solar photovoltaic (PV) modules (solar panels) rose to a record electricity-generating capacity of 28.8 million peak kilowatts (kW) in 2021, from 21.8 million peak kW in 2020, based on data from our Annual Photovoltaic Module Shipments Report. Continued demand for U.S. solar capacity drove this increase in solar panel shipments in 2021, as solar's share of U.S. electricity continued to rise.

U.S. solar panel shipments include imports, exports, and domestically produced and shipped panels. In 2021, about 80% of U.S. solar panel module shipments were imports, primarily from Asia, even as a proposed tenfold increase in solar aims to reshape the U.S. electricity system.

U.S. solar panel shipments closely track domestic solar capacity additions; differences between the two usually result from the lag time between shipment and installation, and long-term projections for solar's generation share provide additional context. We categorize solar capacity additions as either utility-scale (facilities with one megawatt of capacity or more) or small-scale (largely residential solar installations).

The United States added 13.2 gigawatts (GW) of utility-scale solar capacity in 2021, an annual record and 25% more than the 10.6 GW added in 2020, according to our Annual Electric Generator Report. Additions of utility-scale solar capacity reached a record high, reflecting strong growth in solar and storage despite project delays, supply chain constraints, and volatile pricing.

Small-scale solar capacity installations in the United States increased by 5.4 GW in 2021, up 23% from 2020 (4.4 GW), as solar PV and wind power continued to grow amid favorable government plans. Most of the small-scale solar capacity added in 2021 was installed on homes. Residential installations totaled more than 3.9 GW in 2021, compared with 2.9 GW in 2020.

The cost of solar panels has declined significantly since 2010. The average value (a proxy for price) of panel shipments has decreased from $1.96 per peak kW in 2010 to $0.34 per peak kW in 2021, as solar became the third-largest renewable source and markets scaled. Despite supply chain constraints and higher material costs in 2021, the average value of solar panels decreased 11% from 2020.

In 2021, the top five destination states for U.S. solar panel shipments were:

California (5.09 million peak kW)
Texas (4.31 million peak kW)
Florida (1.80 million peak kW)
Georgia (1.15 million peak kW)
Illinois (1.12 million peak kW)
These five states accounted for 46% of all U.S. shipments, and 2023 utility-scale project pipelines point to continued growth.

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Canada’s clean energy sector is expanding as Indigenous communities lead electricity transmission projects, drive sustainable growth, and strengthen energy independence through renewable power, community ownership, and grid connections across remote and regional areas of Canada.

What is Canada’s Clean Energy Sector?

Canada’s clean energy sector encompasses industries and initiatives that generate, transmit, and manage low-carbon electricity to meet the country's national climate goals. It emphasizes Indigenous participation, renewable innovation, and equitable economic growth.

✅ Expands renewable electricity generation and transmission

✅ Builds Indigenous-led ownership and partnerships

✅ Reduces emissions through sustainable energy transition

Canada’s clean energy sector is entering a pivotal era of transformation, with Indigenous communities emerging as leading partners in expanding electricity transmission and renewable infrastructure, including grid modernization projects that are underway nationwide. These communities are not only driving projects that connect remote regions to the grid but also redefining what energy leadership and equity look like in Canada.

At a recent webinar co-hosted by the Canadian Climate Institute and the Indigenous Power Coalition, panellists discussed the growing wave of Indigenous-led electricity transmission projects and the policies needed to strengthen Indigenous participation. The event, moderated by Frank Busch, featured Margaret Kenequanash, CEO of Wataynikaneyap Power; Kahsennenhawe Sky-Deer, Grand Chief of the Mohawk Council of Kahnawà:ke; and Blaise Fontaine, Co-Founder of ProACTIVE Planning Inc. and Indigenous Power Coalition.

The discussion comes at a crucial moment for Canada’s clean energy transition. As the country races to meet its climate commitments and zero-emissions electricity by 2035 targets, demand for clean power is rising rapidly. Historically, energy development in Canada occurred on Indigenous lands without consent or fair participation, but today, Indigenous communities collectively represent the largest clean energy asset owners outside Crown and private utilities.

“There is a genuine appetite for Indigenous communities to not just own transmission projects but to also lead,” said Fontaine. He noted that Indigenous communities are increasingly setting the terms of engagement, selecting partners, and shaping projects in line with their cultural and environmental values.

One of the strongest examples of this transformation is the Wataynikaneyap (Watay) Power Project in northern Ontario, a 1,800-kilometre transmission line connecting 17 remote First Nations communities to the provincial grid. “Communities must fully understand what they are getting into, since it is their homelands that will be impacted,” said Kenequanash. She emphasized that the project’s success came from five years of inter-community meetings to agree on shared principles before any external engagement.

The panel also highlighted the Hertel–New York Interconnection Line, co-owned by Hydro-Québec and the Mohawk Council of Kahnawà:ke, as another milestone in Indigenous energy leadership. Sky-Deer noted that the project’s co-ownership model required Quebec’s National Assembly to pass Bill 13, a first-of-its-kind legal framework. “That was a breakthrough,” she said, “but it also shows that true partnership still depends on one-off exceptions rather than standard policy.”

Panellists agreed that Canada’s regulatory systems have not kept pace with Indigenous leadership. Fontaine called on governments to “think outside the box to avoid staying stuck in the status quo,” emphasizing the need for enabling policies that align with an electric, connected and clean vision for Canada while making Indigenous-led ownership the norm rather than the exception.

Financial readiness is another key factor driving Indigenous participation. Communities are now accessing capital through partnerships with financial institutions and government loan programs, and growing evidence that a 2035 zero-emissions grid is practical and profitable is strengthening investor confidence. The collaboration between the Mohawk Council of Kahnawà:ke and the Caisse de dépôt et placement du Québec exemplifies tailored financing and long-term investment that supports community ownership and sustainable growth.

True equity, however, goes beyond financial participation. “It’s not just about having a percentage stake,” Fontaine explained. “True equity means meaningful decision-making power and control.” Indigenous leaders are insisting on co-governance structures that align with their worldviews, prioritizing environmental protection, cultural respect, and intergenerational stewardship.

The benefits of this approach extend far beyond project economics. Communities involved in ownership experience tangible local benefits, including employment and training opportunities, as well as new investments in education and culture. Hydro-Québec’s $10 million contribution to the Kahnawà:ke Cultural Arts Center is one example of how partnerships can support cultural renewal and community development.

As Canada looks to build east–west electricity interties and expand renewable energy generation, including solar where Canada has lagged in deployment nationwide, Indigenous leadership is becoming increasingly central to national energy policy. Fontaine noted that this shift offers “even greater opportunities for Indigenous-led transmission as Canada connects its provinces rather than just exporting power south.”

In particular, Alberta's energy profile highlights both rapid growth in renewables and ongoing fossil fuel strength, informing intertie planning and market design.

On the National Truth and Reconciliation Day, panellists urged reflection on both the barriers that remain and the opportunities ahead. Indigenous leadership in Canada’s clean energy sector is proving that reconciliation can take tangible form, through ownership, partnership, and shared prosperity.

This transformation represents more than an energy transition; it’s a rebalancing of power, respect, and responsibility, carried out “in a good way,” as the panellists emphasized, and essential to building a clean, inclusive energy future for all Canadians while strengthening the global electricity market position of the country.

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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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Offshore Wind Vessel Charging System enables renewable energy offshore charging from wind turbines, delivering clean power to electric vessels and crew transfer ships, boosting range, safety, and net zero maritime operations with reliable, efficient infrastructure.

Key Points

A turbine-mounted offshore charger delivering renewable power to electric vessels, extending range and improving safety.

✅ Turbine-mounted, field-proven offshore charging interface

✅ Delivers 100% renewable electricity to electric vessels

✅ Accelerates net zero, cuts maritime fossil fuel use

An offshore charging system will power vessels with 100% renewably generated electricity from wind turbines, aligning with projects like battery-electric high-speed ferries now advancing in the United States.

The system, developed by Teesside marine electrical engineering firm MJR Power and Automation, will be presented at the Global Offshore Wind event in Manchester (21-22 June), alongside interest in EV energy storage for buildings that could complement offshore charging solutions.

Known as the Offshore Wind On-Turbine Electrical Vessel Charging System, MJR says the chargepoints will provide efficient, safe and reliable transfer of clean power for crew vehicles and other offshore support vessels, while emerging vehicle-to-grid capacity on wheels concepts highlight the wider role of electric fleets.

“This innovation will break down the existing range barriers and increase the uptake by vessel owners and operators, as demonstrated by electric ships on the B.C. coast moving to fully electric and green propulsion systems for retrofit and new-build vessels,” an announcement said.

“In combination with other field-proven technologies, the charging system will be an important part for government and offshore wind owners and operators to achieve their net zero maritime operations targets, and switch away from fossil fuels, complemented by port initiatives such as all-electric berth at London Gateway now under development. The ability to charge when in the field will significantly accelerate adoption of current emission-free propulsion systems, which will be a major asset for the decarbonisation of the global maritime sector.”

The firm recently announced that construction and in-house testing of the system had been completed. The development project was part of the Clean Maritime Demonstration Competition, funded by the Department for Transport and delivered in partnership with Innovate UK, reflecting wider interest in reversing the charge to the grid for resilient energy systems.

MJR electrical engineer Mohammed Latif said: “Our system will be absolutely crucial in helping governments to deliver on their net zero carbon targets, supported by plans like new UK-Europe interconnectors that strengthen clean energy supply, and I am looking forward to demonstrating how it works and the benefits it offers.”

As part of the project, MJR Power and Automation led a consortium of partners – Ore Catapult, Xceco, Artemis Technologies and Tidal Transit – that all provided expertise.

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Canada Renewable Energy Partnerships advance wind power and clean electricity in Alberta and Saskatchewan, cutting emissions and supporting net-zero goals through Capital Power and SaskPower agreements with Indigenous participation and 25-year supply contracts.

Key Points

Government-backed deals with Capital Power and SaskPower to deliver clean electricity and reduce emissions.

✅ 25-year renewable supply for federal facilities

✅ New Halkirk 2 Wind project in Alberta

✅ Emissions cuts with Indigenous participation

The Government of Canada has partnered with two major energy providers in Western Canada (Prairie provinces) on renewable energy projects.

Tourism Minister Randy Boissonnault appeared in Edmonton on Friday to announce a new Alberta wind-generation facility in partnership with Capital Power.

It's one of two new energy partnerships in Western Canada as part of the 2030 emissions reduction plan by Public Services and Procurement Canada.

On Jan. 1, the federal government awarded a contract worth up to $500 million to Capital Power to provide all federal facilities in Alberta with renewable electricity as part of Alberta's renewable energy surge for 25 years.

"We're proud to partner with the government of Canada to help them reach their 100 per cent clean electricity by 2025 goal," said Jason Comandante, Capital Power vice president of commercial services.

The agreement also includes opportunities for Indigenous participation, including facility development partnerships and employment and training opportunities.

"At Capital Power, we are committed to net-zero by 2045, and are proud to take action against climate change. Collaborative agreements like this help support our net-zero goals, provide us opportunities to meaningfully engage Indigenous communities, and help decarbonize Alberta's power grid," Comandante said.

Capital Power will provide around 250,000 megawatt-hours of electricity each year through existing renewable energy credits while the new Capital Power Halkirk 2 Wind facility is being developed.

Located near Paintearth, Alta., the proposed wind farm will have up to 35 turbines and generate enough power for the average yearly electricity needs of more than 70,000 Alberta homes.

The project is currently awaiting regulatory approval, within Alberta's energy landscape, with construction projected to begin this summer. When complete, it will supply 49 per cent of its output to the federal government.

"Through the agreement, the federal government is supporting the ongoing development of renewable energy infrastructure development within the province," Boissonnault said.

The new partnership will join another in Saskatchewan and complement Alberta solar facilities that have been contracted at lower cost than natural gas.

In 2022, the federal government signed an agreement with SaskPower to supply clean electricity to the approximately 600 federal facilities in Saskatchewan. That wind project is expected to come online by 2024.

Boissonnault said the two initiatives combined will reduce carbon dioxide emissions in Alberta and Saskatchewan by about 166 kilotonnes.

"That is the equivalent of the emissions from more than 50,000 cars driven for one year. So, if you think about that, that's a great reduction right here in Alberta and Saskatchewan," he said.

"These are concrete steps to ensuring that Canada remains a leader of renewable energy on the global stage and grid modernization projects to help the fight against climate change." 

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