Regulation vital for fuelcell boom, says developer

Hydro-Quebec Rate Freeze maintains current electricity rates, aligned with Bill 34, inflation indexing, and energy board oversight, delivering rebates to residential, commercial, and industrial customers and projecting nearly $1 billion in savings across Quebec.

Key Points

A Bill 34 policy holding power rates, adding 2020 rebates, and indexing 2021-2024 rates to inflation for Quebec customers.

✅ 2020-21 rates frozen; savings near $1B over five years.

✅ $500M rebate: residential, commercial, industrial shares.

✅ 2021-2024 rates index to inflation; five-year reviews after 2025.

Hydro-Quebec Distribution will not file a rate adjustment application with the province’s energy board this year, amid a class-action lawsuit alleging customers were overcharged.

In a statement released on Friday the Crown Corporation said it wants current electricity rates to be maintained for another year, as pandemic-driven demand pressures persist, starting April 1. That is consistent with the recently tabled Bill 34, and echoes Ontario legislation to lower electricity rates in its aims, which guarantees lower electricity rates for Quebecers.

The bill also provides a $500 million rebate in 2020, similar to a $535 million refund previously issued, half of which will go to residential customers while $190 million will go to commercial customers and another $60 million to industrial ones.

Hydro-Quebec said the 2020-21 rate freeze will generate savings of nearly $1 billion for its clients over the next five years, even as Manitoba Hydro scales back increases in a different market.

Bill 34, which was tabled in June, also proposes to set rates based on inflation for the years 2021 to 2024, contrasting with Ontario rate increases over the same period. After 2025 Hydro-Quebec would have to ask the energy board to set new rates every five years, as opposed to the current annual system, while BC Hydro is raising rates by comparison.

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New England Solar Interconnection Costs highlight distributed generation strains, transmission charges, distribution upgrades, and DAF fees as National Grid maps hosting capacity, driving queue delays and FERC disputes in Rhode Island and Massachusetts.

Key Points

Rising upfront grid upgrade and DAF charges for distributed solar in RI and MA, including some transmission costs.

✅ Upfront grid upgrades shifted to project developers

✅ DAF and transmission charges increase per MW costs

✅ Queue delays tied to hosting capacity and cluster studies

Solar developers in Rhode Island and Massachusetts say soaring charges to interconnect with the electric grid are threatening the viability of projects. 

As more large-scale solar projects line up for connections, developers are being charged upfront for the full cost of the infrastructure upgrades required, a long-common practice that they say is now becoming untenable amid debates over a new solar customer charge in Nova Scotia. 

“It is a huge issue that reflects an under-invested grid that is not ready for the volume of distributed generation that we’re seeing and that we need, particularly solar,” said Jeremy McDiarmid, vice president for policy and government affairs at the Northeast Clean Energy Council, a nonprofit business organization. 

Connecting solar and wind systems to the grid often requires upgrades to the distribution system to prevent problems, such as voltage fluctuations and reliability risks highlighted by Australian distributors in their networks. Costs can vary considerably from place to place, depending on the amount of distributed generation coming online and the level of capacity planning by regulators, said David Feldman, a senior financial analyst at the National Renewable Energy Laboratory.

“Certainly the Northeast often has more distribution challenges than much of the rest of the country just because it’s more populous and often the infrastructure is older,” he said. “But it’s not unique to the Northeast — in the Midwest, for example, there’s a significant amount of wind projects in the queues and significant delays.”

In Rhode Island and Massachusetts, where strong incentive programs are driving solar development, the level of solar coming online is “exposing the under-investment in the distribution system that is causing these massive costs that National Grid is assigning to particular projects or particular groups of projects,” McDiarmid said. “It is going to be a limiting factor for how much clean energy we can develop and bring online.”

Frank Epps, chief executive officer at Energy Development Partners, has been developing solar projects in Rhode Island since 2010. In that time, he said, interconnection charges on his projects have grown from about $80,000-$120,000 per megawatt to more than $400,000 per megawatt. He attributed the increase to a lack of investment in the distribution network by National Grid over the last decade.

He and other developers say the utility is now adding further to their costs by passing along not just the cost of improving the distribution system — the equivalent of the city street of the grid that brings power directly to customers — but also costs for modifying the transmission system — the interstate highway that moves bulk power over long distances to substations. 

Solar developers who are only requesting to hook into the distribution system, and not applying for transmission service, say they should not be charged for those additional upgrades under state interconnection rules unless they are properly authorized under the federal law that governs the transmission system. 

A Rhode Island solar and wind developer filed a complaint with the Federal Energy Regulatory Commission in February over transmission system improvement charges for its four proposed solar projects. Green Development said National Grid subsidiaries Narragansett Electric and New England Power Company want to charge the company more than $500,000 a year in operating and maintenance expenses assessed as so-called direct assignment facility charges. 

“This amount nearly doubles the interconnection costs associated with the projects,” which total 38.4 megawatts in North Smithfield, the company says in its complaint. “Crucially, these charges are linked to recovering costs associated with providing transmission service — even though no such transmission service is being provided to Green Development.”

But Ted Kresse, a spokesperson for National Grid, said the direct assignment facility, or DAF, construct has been in place for decades and has been applied to any customer affecting the need for transmission upgrades.

“It is the result of the high penetration and continued high volume of distributed generation interconnections that has recently prompted the need for transmission upgrades, and subsequently the pass-through of the associated DAF charges,” he said. 

Several complaints before the Rhode Island Public Utilities Commission object to these DAF and other transmission charges.

One petition for dispute resolution concerns four solar projects totaling 40 MW being developed by Energy Development Partners in a former gravel pit in North Kingstown. Brown University has agreed to purchase the power. 

The developer signed interconnection service agreements with Narragansett Electric in 2019 requiring payment of $21.6 million for costs associated with connecting the projects at a new Wickford Junction substation. Last summer, Narragansett sought to replace those agreements with new ones that reclassified a portion of the costs as transmission-level costs, through New England Power, National Grid’s transmission subsidiary.

That shift would result in additional operational and maintenance charges of $835,000 per year for the estimated 35-year life of the projects, the complaint says.

“This came as a complete shock to us,” Epps said. “We’re not just paying for the maintenance of a new substation. We are paying a share of the total cost that the system owner has to own and operate the transmission system. So all of the sudden, it makes it even tougher for distributed energy resources to be viable.”

In its response to the petition, National Grid argues that the charges are justified because the solar projects will require transmission-level upgrades at the new substation. The company argues that the developer should be responsible for the costs rather than ratepayers, “who are already supporting renewable energy development through their electric rates.”

Seth Handy, one of the lawyers representing Green Development in the FERC complaint, argues that putting transmission system costs on distribution assets is unfair because the distributed resources are “actually reducing the need to move electricity long distances. We’ve been fighting these fights a long time over the underestimating of the value of distributed energy in reducing system costs.”

Handy is also representing the Episcopal Diocese of Rhode Island before the state Supreme Court in its appeal of an April 2020 public utilities commission order upholding similar charges for a proposed 2.2-megawatt solar project at the diocese’s conference center and camp in Glocester. 

Todd Bianco, principal policy associate at the utilities commission, said neither he nor the chairperson can comment on the pending dockets contesting these charges. But he noted that some of these issues are under discussion in another docket examining National Grid’s standards for connecting distributed generation. Among the proposals being considered is the appointment of an independent ombudsperson to resolve interconnection disputes. 

Separately, legislation pending before the Rhode Island General Assembly would remove responsibility for administering the interconnection of renewable energy from utilities, and put it under the authority of the Rhode Island Infrastructure Bank, a financing agency.

Handy, who recently testified in support of the bill, said he believes National Grid has too many conflicting interests to administer interconnecting charges in a timely, transparent and fair fashion, and pointed to utility moves such as changes to solar compensation in other states as examples. In particular, he noted the company’s interests in expanding natural gas infrastructure. 

“There are all kinds of economic interests that they have that conflict with our state policy to provide lower-cost renewable energy and more secure energy solutions,” Handy said.

In testimony submitted to the House Committee on Corporations opposing the legislation, National Grid said such powers are well beyond the purpose and scope of the infrastructure bank. And it cited figures showing Rhode Island is third in the country for the most installed solar per square mile (behind New Jersey and Massachusetts).

Nadav Enbar, program manager at the Electric Power Research Institute, a nonprofit research organization for the utility industry, said interconnection delays and higher costs are becoming more common due to “the incredible uptake” in distributed renewable energy, particularly solar.

That’s impacting hosting capacity, the room available to connect all resources to a circuit without causing adverse harm to reliability and safety. 

“As hosting capacity is being reduced, it’s causing an increasing number of situations where utilities need to study their systems to guarantee interconnection without compromising their systems,” he said. “And that is the reason why you’re starting to see some delays, and it has translated into some greater costs because of the need for upgrades to infrastructure.”

The cost depends on the age or absence of infrastructure, projected load growth, the number of renewable energy projects in the queue, and other factors, he said. As utilities come under increasing pressure to meet state renewable goals, and as some states pilot incentives like a distributed energy rebate in Illinois to drive utility innovation, some (including National Grid) are beginning to provide hosting capacity maps that provide detailed information to developers and policymakers about the amount of distributed energy that can be accommodated at various locations on the grid, he said. 

In addition, the coming availability of high-tech “smart inverters” should help ease some of these problems because they provide the grid with more flexibility when it comes to connecting and communicating with distributed energy resources, Enbar said. 

In Massachusetts, the Department of Public Utilities has opened a docket to explore ways to better plan for and share the cost of upgrading distribution infrastructure to accommodate solar and other renewable energy sources as part of a grid overhaul for renewables nationwide. National Grid has been conducting “cluster studies” there that attempt to analyze the transmission impacts of a group of solar projects and the corresponding interconnection cost to each developer.

Kresse, of National Grid, said the company favors cost-sharing methodologies under consideration that would “provide a pathway to spread cost over the total enabled capacity from the upgrade, as opposed to spreading the cost over only those customers in the queue today.” 

Solar developers want regulators to take an even broader approach that factors in how the deployment of renewables and the resulting infrastructure upgrades benefit not just the interconnecting generator, but all customers. 

“Right now, if your project is the one that causes a multimillion-dollar upgrade, you are assigned that cost even though that upgrade is going to benefit a lot of other projects, as well as make the grid stronger,” said McDiarmid, of the clean energy council. “What we’re asking for is a way of allocating those costs among a variety of developers, as well as to the grid itself, meaning ratepayers. There’s a societal benefit to increasing the modernization of the grid, and improving the resilience of the grid.”

In the meantime, BlueHub Capital, a Boston-based solar developer focused on serving affordable housing developments, recently learned from National Grid that, as a part of one of the area studies, it will be required to pay $5.8 million in transmission and distribution upgrades to interconnect a 2-megawatt solar-plus-storage project that leverages cheaper batteries to enhance resilience, approved for a brownfield site in Gardner, Massachusetts. 

According to testimony submitted to the department, the sum is supposed to be paid within the next year, even though the project will have to wait to be interconnected until April 2027, when a new transmission line is completed. In addition, BlueHub will be responsible for DAF charges totaling $3.4 million over the 20-year life of the project. 

“We’re being asked to pay a fortune to provide solar that the state wants,” said DeWitt Jones, BlueHub’s president. “It’s so expensive that the upgrades are driving everyone out of the interconnection queue. The costs stay the same, but they fall on fewer projects. We need a process of grid design and modernization to guide this.”

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Trump NEPA Overhaul streamlines environmental reviews, tightening 'reasonably foreseeable' effects, curbing cumulative impacts, codifying CEQ greenhouse gas guidance, expediting permits for pipelines, highways, and wind projects with two-year EIS limits and one lead agency.

Key Points

Trump NEPA Overhaul streamlines reviews, trims cumulative impacts, keeps GHG analysis for foreseeable effects.

✅ Limits cumulative and indirect impacts; emphasizes foreseeable effects

✅ Caps EIS at two years; one-year environmental assessments

✅ One lead agency; narrower NEPA triggers for low federal funding

President Trump has announced plans for overhauling rules surrounding the nation’s bedrock environmental law, and administration officials refuted claims they were downplaying greenhouse gas emissions, as the administration also pursues replacement power plant rules in related areas.

The president, during remarks at the White House with supporters and Cabinet officials, said he wanted to fix the nation’s “regulatory nightmare” through new guidelines for implementing the National Environmental Policy Act.

“America is a nation of builders,” he said. But it takes too long to get a permit, and that’s “big government at its absolute worst.”

The president said, “We’re maintaining America’s world-class standards of environmental protection.” He added, “We’re going to have very strong regulation, but it’s going to go very quickly.”

NEPA says the federal government must consider alternatives to major projects like oil pipelines, highways and bridges that could inflict environmental harm. The law also gives communities input.

The Council on Environmental Quality has not updated the implementing rules in decades, and both energy companies and environmentalists want them reworked, even as some industry groups warned against rushing electricity pricing changes under related policy debates.

But they patently disagree on how to change the rules.

A central fight surrounds whether the government considers climate change concerns when analyzing a project.

Environmentalists want agencies to look more at “cumulative” or “indirect” impacts of projects. The Trump plan shuts the door on that.

“Analysis of cumulative effects is not required,” the plan states, adding that CEQ “proposes to make amendments to simplify the definition of effects by consolidating the definition into a single paragraph.”

CEQ Chairwoman Mary Neumayr told reporters during a conference call that definitions in the current rules were the “subject of confusion.”

The proposed changes, she said, do in fact eliminate the terms “cumulative” and “indirect,” in favor of more simplified language.

Effects must be “reasonably foreseeable” and require a “reasonably close causal relationship” to the proposed action, she added. “It does not exclude considerations of greenhouse gas emissions,” she said, pointing to parallel EPA proposals for new pollution limits on coal and gas power plants as context.

Last summer, CEQ issued proposed guidance on greenhouse gas reviews in project permitting. The nonbinding document gave agencies broad authority when considering emissions (Greenwire, June 21, 2019).

Environmentalists scoffed and said the proposed guidance failed to incorporate the latest climate science and look at how projects could be more resilient in the face of severe weather and sea-level rise.

The proposed NEPA rules released today include provisions to codify the proposed guidance, which has also been years in the making.

Other provisions

Senior administration officials sought to downplay the effect of the proposed NEPA rules by noting the underlying statute will remain the same.

“If it required NEPA yesterday, it will require NEPA under the new proposal,” an official said when asked how the changes might apply to pipelines like Keystone XL.

And yet the proposed changes could alter the “threshold consideration” that triggers NEPA review. The proposal would exclude projects with minimal federal funding or “participation.”

The Trump plan also proposes restricting an environmental impact statement to two years and an environmental assessment to one.

Neumayr said the average EIS takes 4 ½ years and in some cases longer. Democrats have disputed those timelines. Further, just 1% of all federal actions require an EIS, they argue.

The proposal would also require one agency to take the lead on permitting and require agency officials to “timely resolve disputes that may result in delays.”

In general, the plan calls for environmental documents to be “concise” and “serve their purpose of informing decision makers.”

Both Interior Secretary David Bernhardt and EPA Administrator Andrew Wheeler, whose agency moved to rewrite coal power plant wastewater limits in separate actions, were at the White House for the announcement.

Reaction

An onslaught of critics have said changes to NEPA rules could be the administration’s most far-reaching environmental rollback, and state attorneys general have mounted a legal challenge to related energy actions as well.

The League of Conservation Voters declared the administration was again trying to “sell out the health and well-being of our children and families to corporate polluters.”

On Capitol Hill, House Speaker Nancy Pelosi (D-Calif.) said during a news conference the administration would “no longer enforce NEPA.”

“This means more polluters will be right there, next to the water supply of our children,” she said. “That’s a public health issue. Their denial of climate, they are going to not use the climate issue as anything to do with environmental decisionmaking.”

Sen. Sheldon Whitehouse (D-R.I.) echoed the sentiment, saying he didn’t need any more proof that the fossil fuel industry had hardwired the Trump administration “but we got it anyway.”

Energy companies, including firms focused on renewable energy development, are welcoming the “clarity” of the proposed NEPA rules, even as debates continue over a clean electricity standard in federal climate policy.

“The lack of clarity in the existing NEPA regulations has led courts to fill the gaps, spurring costly litigation across the sector, and has led to unclear expectations, which has caused significant and unnecessary delays for infrastructure projects across the country,” the Interstate Natural Gas Association of America said in a statement.

Last night, the American Wind Energy Association said NEPA rules have caused “unreasonable and unnecessary costs and long project delays” for land-based and offshore wind energy and transmission development.

Trump has famously attacked the wind energy industry for decades, dating back to his opposition to a Scottish wind turbine near his golf course.

The president today said he won’t stop until “gleaming new infrastructure has made America the envy of the world again.”

When asked whether he thought climate change was a “hoax,” as he once tweeted, he said no. “Nothing’s a hoax about that,” he said.

The president said there’s a book about climate he’s planning to read. He said, “It’s a very serious subject.”

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U.S. Wind Generation surpassed hydroelectric output in 2019, EIA data shows, becoming the top renewable electricity source, driven by PTC incentives, expanded capacity, and utility-scale projects across states, boosting the national electricity mix.

Key Points

U.S. Wind Generation is the nation's top renewable, surpassing hydro as EIA-tracked capacity grows under PTC incentives.

✅ EIA: wind topped hydro in 2019, over 300M MWh generated

✅ PTC credits spurred growth in utility-scale wind projects

✅ 103 GW installed; 77% added in the last decade

Last year saw wind power surging in the U.S. to overtake hydroelectric generation for the first time, according to data from the U.S. Energy Information Administration (EIA).

Released Wednesday, the figures from the EIA’s “Electric Power Monthly” report show that yearly wind generation hit a little over 300 million megawatt hours (MWh) in 2019. This was roughly 26 million MWh more than hydroelectric production.

Wind now represents the “most-used renewable electricity generation source” in the U.S., the EIA said, and renewables hit a 28% monthly record in April in later data.

Overall, total renewable electricity generation — which includes sources such as solar's 4.7% share in 2022 as one example, geothermal and landfill gas — at utility scale facilities hit more than 720 million MWh in 2019, compared to just under 707 million MWh in 2018. To put things in perspective, generation from coal came to more than 966 million MWh in 2019, while renewables surpassed coal in 2022 nationally according to later analyses.

According to the EIA’s “Today in Energy” briefing, which was also published Wednesday, generation from wind power has grown “steadily” across the last decade, and by 2020, renewables became the second-most prevalent source in the U.S. power mix.

This, it added, was partly down to the extension of the Production Tax Credit, or PTC, amid favorable government plans supporting solar and wind growth. According to the EIA, the PTC is a system which gives operators a tax credit per kilowatt hour of renewable electricity production. It applies for the first 10 years of a facility’s operation.

At the end of 2019, the country was home to 103 gigawatts (GW) of wind capacity, with 77% of this being installed in the last decade, and wind capacity surpassed hydro in 2016 according to industry data. The U.S. is home 80 GW of hydroelectric capacity, according to the EIA.

“The past decade saw a steady increase in wind capacity across the country and we capped the decade with a monumental achievement for the industry in reaching more than 100 GW,” Tom Kiernan, the American Wind Energy Association’s CEO, said in a statement issued Thursday.

“And more wind energy is coming, as the industry is well into investing $62 billion in new projects over the next few years that put us on the path to achieving 20 percent of the nation’s electricity mix in 2030,” Kiernan went on to state.

“As a result, wind is positioned to remain the largest renewable energy generator in the country for the foreseeable future.”

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Alberta Solar Energy Contracts secure low-cost photovoltaic PPAs for government operations, delivering renewable electricity at 4.8 cents/kWh, beating natural gas LCOE, enhancing summer grid efficiency across Hays, Tilley, and Jenner with Canadian Solar.

Key Points

Low-cost PV power agreements meeting 55% of Alberta government electricity demand via new Canadian Solar facilities.

✅ Price: 4.8 cents/kWh CAD, under gas-fired generation LCOE.

✅ Sites: Hays, Tilley, Jenner; 50% equity with Conklin Métis Local #193.

✅ Supplies 55% of provincial government electricity demand.

Three new solar electricity facilities to be built in south eastern Alberta (Canada) amid Alberta's solar growth have been selected through a competitive process to supply the Government of Alberta with 55 per cent of their annual electricity needs. The facilities will be built near Hays, Tilley, and Jenner, by Canadian Solar with Conklin Métis Local #193 as 50-percent equity owners.

The Government of Alberta's operations have been powered 100 per cent with wind power since 2007. Upon the expiration of some of these contracts, they have been renewed to switch from wind to solar energy. The average contract pricing will be $0.048 per kilowatt hour (3.6 cents/kWh USD), which is less than the average historical wholesale power pool price paid to natural gas-fired electricity in the province in years 2008 - 2018.

"The conversation about solar energy has long been fixated on its price competitiveness with fossil fuels," said John Gorman, CanSIA President & CEO. "Today's announcement demonstrates that low cost solar energy has arrived as a mainstream option in Alberta, even as demand for solar lags in Canada according to federal assessments. The conversation should next focus on how to optimize an all-of-the-above strategy for developing the province's renewable and non-renewable resources."

"This price discovery is monumental for the solar industry in Canada" said Patrick Bateman, CanSIA Director of Policy & Market Development. "At less than five cents per kilowatt hour, this solar electricity has a cost that is less than that of natural gas. Achieving Alberta's legislated 30 per cent by 2030 renewable electricity target just became a whole lot cheaper!".

Quick Facts:

• The contract price of 4.8 cents/kWh CAD to be paid by Alberta Infrastructure for this solar electricity represents a lower Levelized Cost of Electricity (LCOE) than the average annual wholesale price paid by the power pool to combined-cycle and single-cycle natural gas-fired electricity generation which was 7.1 cents/kWh and 11.2 cents/kWh respectively from 2008 - 2018.

• Alberta receives more hours of sunshine than Miami, Florida in the summer months. Alberta's electricity supply is most strained in summer, highlighting challenges for solar expansion when high temperatures increase the resistance of the distribution and transmission systems, and reduce the efficiency of cooling thermal power plants. For this reason, solar facilities sited near to electricity demand improves overall grid efficiency. Supply shortages are atypical in Alberta in winter when solar energy is least available. When they do occur, imports are increased and large loads are decreased.

• In 2018, Alberta's solar electricity generation exceeded 50 MW. While representing much less than 1% of the province's electricity supply today, the Canadian Solar Industries Association (CanSIA) forecasts that solar energy could supply as much as 3 per cent of the province's electricity by 2030, supporting renewable energy job growth across Alberta. A recent supply chain study of the solar electricity sector in Alberta by Solas Energy Consulting Inc. found a potential of $4.1 billion in market value and a labour force rising to 10,000 in 2030.

To learn more about solar energy and the best way for consumers to go solar, please visit the Canadian Solar Industries Association at www.CanSIA.ca.

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EV Decarbonization Strategy weighs life-cycle emissions and climate targets, highlighting mode shift to public transit, cycling, and walking, grid decarbonization, renewable energy, and charging infrastructure to cut greenhouse gases while reducing private car dependence.

Key Points

A plan to cut transport emissions by pairing EV adoption with mode shift, clean power, and less private car use.

✅ Prioritize mode shift: transit, cycling, and walking.

✅ Electrify remaining vehicles with clean, renewable power.

✅ Expand charging, improve batteries, and manage critical minerals.

California recently announced that it plans to ban the sales of gas-powered vehicles by 2035, a move similar to a 2035 electric vehicle mandate seen elsewhere, Ontario has invested $500 million in the production of electric vehicles (EVs) and Tesla is quickly becoming the world's highest-valued car company.

It almost seems like owning an electric vehicle is a silver bullet in the fight against climate change, but it isn't, as a U of T study explains today. What we should also be focused on is whether anyone should use a private vehicle at all.
 
As a researcher in sustainable mobility, I know this answer is unsatisfying. But this is where my latest research has led.

Battery EVs, such as the Tesla Model 3 - the best selling EV in Canada in 2020 - have no tailpipe emissions. But they do have higher production and manufacturing emissions than conventional vehicles, and often run on electricity that comes from fossil fuels.

Almost 18 per cent of the electricity generated in Canada came from fossil fuels in 2019, and even as Canada's EV goals grow more ambitious today, the grid mix varies from zero in Quebec to 90 per cent in Alberta.
 
Researchers like me compare the greenhouse gas emissions of an alternative vehicle, such as an EV, with those of a conventional vehicle over a vehicle lifetime, an exercise known as a life-cycle assessment. For example, a Tesla Model 3 compared with a Toyota Corolla can provide up to 75 per cent reduction in greenhouse gases emitted per kilometre travelled in Quebec, but no reductions in Alberta.

Hundreds of millions of new cars

To avoid extreme and irreversible impacts on ecosystems, communities and the overall global economy, we must keep the increase in global average temperatures to less than 2 C - and ideally 1.5 C - above pre-industrial levels by the year 2100.

We can translate these climate change targets into actionable plans. First, we estimate greenhouse gas emissions budgets using energy and climate models for each sector of the economy and for each country. Then we simulate future emissions, taking alternative technologies into account, as well as future potential economic and societal developments.

I looked at the U.S. passenger vehicle fleet, which adds up to about 260 million vehicles, while noting the potential for Canada-U.S. collaboration in this transition, to answer a simple question: Could the greenhouse gas emissions from the sector be brought in line with climate targets by replacing gasoline-powered vehicles with EVs?

The results were shocking. Assuming no changes to travel behaviours and a decarbonization of 80 per cent of electricity, meeting a 2 C target could require up to 300 million EVs, or 90 per cent of the projected U.S. fleet, by 2050. That would require all new purchased vehicles to be electric from 2035 onwards.

To put that into perspective, there are currently 880,000 EVs in the U.S., or 0.3 per cent of the fleet. Even the most optimistic projections, despite hype about an electric-car revolution gaining steam, from the International Energy Agency suggest that the U.S. fleet will only be at about 50 per cent electrified by 2050.

Massive and rapid electrification

Still, 90 per cent is theoretically possible, isn't it? Probably, but is it desirable?

In order to hit that target, we'd need to very rapidly overcome all the challenges associated with EV adoption, such as range anxiety, the higher purchase cost and availability of charging infrastructure.
 
A rapid pace of electrification would severely challenge the electricity infrastructure and the supply chain of many critical materials for the batteries, such as lithium, manganese and cobalt. It would require vast capacity of renewable energy sources and transmission lines, widespread charging infrastructure, a co-ordination between two historically distinct sectors (electricity and transportation systems) and rapid innovations in electric battery technologies. I am not saying it's impossible, but I believe it's unlikely.

Read more: There aren't enough batteries to electrify all cars - focus on trucks and buses instead

So what? Shall we give up, accept our collective fate and stop our efforts at electrification?

On the contrary, I think we should re-examine our priorities and dare to ask an even more critical question: Do we need that many vehicles on the road?

Buses, trains and bikes

Simply put, there are three ways to reduce greenhouse gas emissions from passenger transport: avoid the need to travel, shift the transportation modes or improve the technologies. EVs only tackle one side of the problem, the technological one.

And while EVs do decrease emissions compared with conventional vehicles, we should be comparing them to buses, including leading electric bus fleets in North America, trains and bikes. When we do, their potential to reduce greenhouse gas emissions disappears because of their life cycle emissions and the limited number of people they carry at one time.

If we truly want to solve our climate problems, we need to deploy EVs along with other measures, such as public transit and active mobility. This fact is critical, especially given the recent decreases in public transit ridership in the U.S., mostly due to increasing vehicle ownership, low gasoline prices and the advent of ride-hailing (Uber, Lyft)

Governments need to massively invest in public transit, cycling and walking infrastructure to make them larger, safer and more reliable, rather than expanding EV subsidies alone. And we need to reassess our transportation needs and priorities.

The road to decarbonization is long and winding. But if we are willing to get out of our cars and take a shortcut through the forest, we might get there a lot faster.

Author: Alexandre Milovanoff - Postdoctoral Researcher, Environmental Engineering, University of Toronto 

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