Saint John Energy earns ESRI CanadaÂ’s Award of Excellence

By Directions Magazine


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ESRI Canada recognized Saint John Energy with the Award of Excellence at the Regional User Conference in Fredericton. Eric Melanson, Atlantic Regional Manager for ESRI Canada, presented the award to recognize Saint John Energy on their innovative and integrated approach to application deployment that has dramatically improved efficiencies across the utility.

“Saint John Energy has proactively taken an enterprise approach to GIS that has resulted in more efficient management processes and consistency throughout the company,” explained Eric Melanson, Atlantic Regional Manager. “They have successfully transitioned from a paper-based environment and have implemented key business applications built on GIS that automate and streamline their operations.”

Saint John Energy is an electric distribution utility that serves 36,000 customers in Saint John, New Brunswick. The companyÂ’s network consists of 13 substations and 84 feeders within its service area of 333 square kilometres. For six consecutive years, Saint John Energy was rated one of the top five utilities in Canada for its health and safety record in the less than 500 employee category as monitored by the Canadian Electricity Association.

In 2001, this utility embarked on an ambitious Enterprise Application Project (EAP) to implement three core technologies – management, customer and geographic information systems. The completion of this project resulted in a seamless transition from paper-based systems to an era of digital spatial data. As a first step, Saint John Energy worked with ESRI Canada to create a data collection tool that would enable them to survey their vast infrastructure, and within one year, they captured approximately 200,000 attributed sub-meter GPS locations. This data collection tool was used for everything from citing substations, assessing insurance claims, planning new infrastructure and locating existing underground infrastructure.

In 2006, Saint John Energy initiated a pilot project to implement Automated Meter Infrastructure (AMI) systems that detect when a meter has experienced an outage. Upon rollout of this project, AMI meter data was integrated with data from the Customer Information System (CIS) so that customer information could be accessed with the click of a button using ArcMap.

As part of their integration strategy from the EAP project, Saint John Energy recently selected Telvent Miner & MinerÂ’s Designer application to automate the generation of cost estimates and bills of materials. Designer automatically determines inventory that is required and performs a series of engineering calculations based on standard construction practices.

“Designer provides us with a streamlined information flow from the field through to our operations, engineering, finance and store departments,” explains Bob Bernard, GIS Administrator, Saint John Energy. “This will enable our field employees to perform their job more effectively while delivering a high quality and consistent level of service to our customers.”

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Pennsylvania Home to the First 100% Solar, Marriott-Branded U.S. Hotel

Courtyard by Marriott Lancaster Solar Array delivers 100% renewable electricity via photovoltaic panels at Greenfield Corporate Center, Pennsylvania, a High Hotels and Marriott sustainability initiative reducing grid demand and selling excess power for efficient operations.

 

Key Points

A $1.5M PV installation powering the 133-room hotel with 100% renewable electricity in Greenfield Center, Lancaster.

✅ 2,700 PV panels generate 1,239,000 kWh annually

✅ First Marriott in the US with 100% solar electricity

✅ $504,900 CFA grant; excess power sold to the utility

 

High Hotels Ltd., a hotel developer and operator, recently announced it is installing a $1.5 million solar array that will generate 100% of the electrical power required to operate one of its existing hotels in Greenfield Corporate Center. The completed installation will make the 133-room Courtyard by Marriott-Lancaster the first Marriott-branded hotel in the United States with 100% of its electricity needs generated from solar power. It is also believed to be the first solar array in the country installed for the sole purpose of generating 100% of the electricity needs of a hotel, mirroring how other firms are commissioning their first solar power plant to meet sustainability goals.

“This is an exciting approach to addressing our energy needs that aligns very well with High’s commitment to environmental stewardship,”

“We’ve been advancing many environmentally responsible practices across our hotel portfolio, including converting the interior and exterior lighting at the Lancaster Courtyard to LED, which will lower electricity demand by 15%,” said Russ Urban, president of High Hotels. “Installing solar is another important step in this progression, and we will look to apply lessons from this as we expand our portfolio of premium select-service hotels.”

The Lancaster-based hotel developer, owner and operator is working in partnership with Marriott International Inc. to realize this vision, in step with major brands announcing new clean energy projects across their portfolios.

The installation of more than 2,700 ballasted photovoltaic panels will fill an area more than two football fields in size. After evaluating several on-site and near-site alternatives, High Hotels decided to install the solar array on the roof of a nearby building in Greenfield Corporate Center. Using the existing roof saves more than three acres of open land and has additional aesthetic benefits, aligning with recommendations for solar farms under consideration by local planners. The solar array will produce 1,239,000 kWh of power for the hotel, which consumes 1,177,000 kWh. Any excess power will be sold to the utility, though affordable solar batteries are making on-site storage increasingly feasible.

High Hotels received a grant of $504,900 from the Commonwealth Financing Authority (CFA) through the Solar Energy Program to complete the project. An independent agency of the Department of Community and Economic Development (DCED), the CFA is responsible for evaluating projects and awarding funds for a variety of economic development programs, including the Solar Energy Program and statewide initiatives like solar-power subscriptions that broaden access. The project will receive a solar renewable energy credit which will be conveyed to the CFA to provide the agency with more funds to offer grants in the future.

“This is a cutting-edge project that is exactly the kind we are looking for to promote the generation and use of solar energy,” said DCED Secretary Dennis Davin. “I am very pleased that the first Marriott in the US to receive 100% of its electric needs through renewable solar energy is located right here in Central Pennsylvania.” Secretary Davin also serves as chairman of the CFA’s board.

Panels for the solar array will be Q Cells manufactured by Hanwha Cells Co., Ltd., headquartered in Seoul, South Korea. Ephrata, Pa.-based Meadow Valley Electric Inc. will install the array in the second and third quarters of 2018 with commissioning targeted for September 2018.

 

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B.C. ordered to pay $10M for denying Squamish power project

Greengen Misfeasance Ruling details a B.C. Supreme Court decision awarding $10.125 million over wrongfully denied Crown land and water licence permits for a Fries Creek run-of-river hydro project under a BC Hydro contract.

 

Key Points

A B.C. Supreme Court ruling awarding $10.125M for wrongful denial of Crown land and water licences on Greengen's project.

✅ $10.125M damages for misfeasance in public office

✅ Denial of Crown land tenure and water licence permits

✅ Tied to Fries Creek run-of-river and BC Hydro EPA

 

A B.C. Supreme Court judge has ordered the provincial government to pay $10.125 million after it denied permits to a company that wanted to build a run-of-the river independent power project near Squamish.

In his Oct. 10 decision, Justice Kevin Loo said the plaintiff, Greengen Holdings Ltd., “lost an opportunity to achieve a completed and profitable hydro-electric project” after government representatives wrongfully exercised their legal authority, a transgression described in the ruling as “misfeasance,” with separate concerns reflected in an Ontario market gaming investigation reported elsewhere.

Between 2003 and 2009, the company sought to develop a hydro-electric project on and around Fries Creek, which sits opposite the Brackendale neighbourhood on the other side of the Squamish River. To do so, Greengen Holdings Ltd. required a water licence from the Minister of the Environment and tenure over Crown land from the Minister of Agriculture.

After a lengthy process involving extensive communications between Greengen and various provincial and other ministries and regulatory agencies, the permits were denied, according to Loo. Both decisions cited impacts on Squamish Nation cultural sites that could not be mitigated.

Elsewhere, an Indigenous-owned project in James Bay proceeded despite repeated denials, underscoring varied approaches to community participation.

40-year electricity plan relied on Crown land
The case dates back to December 2005, when BC Hydro issued an open call for power with Greengen. The company submitted a tender several months later.

On July 26, 2006, BC Hydro awarded Greengen an energy purchase agreement, amid evolving LNG electricity demand across the province, under which Greengen would be entitled to supply electricity at a fixed price for 40 years.

Unlike conventional hydroelectric projects, such as new BC generating stations recently commissioned, which store large volumes of water in reservoirs, and in so doing flood large tracts of land, a run of the river project often requires little or no water storage. Instead, from a high elevation, they divert water from a stream or river channel.

Water is then sent into a pressured pipeline known as a penstock, and later passed through turbines to generate electricity, Loo explained, as utilities pursue long-term plans like the Hydro-Québec strategy to reduce fossil fuel reliance. The system returns water to the original stream or river, or into another body of water. 

The project called for most of that infrastructure to be built on Crown land, according to the ruling.

All sides seemed to support the project
In early 2005, company principle Terry Sonderhoff discussed the Fries Creek project in a preliminary meeting with Squamish Nation Chief Ian Campbell.

“Mr. Sonderhoff testified that Chief Campbell seemed supportive of the project at the time,” Loo said.

 

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Its Electric Grid Under Strain, California Turns to Batteries

California Battery Storage is transforming grid reliability as distributed energy, solar-plus-storage, and demand response mitigate rolling blackouts, replace peaker plants, and supply flexible capacity during heat waves and evening peaks across utilities and homes.

 

Key Points

California Battery Storage uses distributed and utility batteries to stabilize power, shift solar, and curb blackouts.

✅ Supplies flexible capacity during peak demand and heat waves

✅ Enables demand response and replaces gas peaker plants

✅ Aggregated assets form virtual power plants for grid support

 

Last month as a heat wave slammed California, state regulators sent an email to a group of energy executives pleading for help to keep the lights on statewide. “Please consider this an urgent inquiry on behalf of the state,” the message said.

The manager of the state’s grid was struggling to increase the supply of electricity because power plants had unexpectedly shut down and demand was surging. The imbalance was forcing officials to order rolling blackouts across the state for the first time in nearly two decades.

What was unusual about the emails was whom they were sent to: people who managed thousands of batteries installed at utilities, businesses, government facilities and even homes. California officials were seeking the energy stored in those machines to help bail out a poorly managed grid and reduce the need for blackouts.

Many energy experts have predicted that batteries could turn homes and businesses into mini-power plants that are able to play a critical role in the electricity system. They could soak up excess power from solar panels and wind turbines and provide electricity in the evenings when the sun went down or after wildfires and hurricanes, which have grown more devastating because of climate change in recent years. Over the next decade, the argument went, large rows of batteries owned by utilities could start replacing power plants fueled by natural gas.

But that day appears to be closer than earlier thought, at least in California, which leads the country in energy storage. During the state’s recent electricity crisis, more than 30,000 batteries supplied as much power as a midsize natural gas plant. And experts say the machines, which range in size from large wall-mounted televisions to shipping containers, will become even more important because utilities, businesses and homeowners are investing billions of dollars in such devices.

“People are starting to realize energy storage isn’t just a project or two here or there, it’s a whole new approach to managing power,” said John Zahurancik, chief operating officer at Fluence, which makes large energy storage systems bought by utilities and large businesses. That’s a big difference from a few years ago, he said, when electricity storage was seen as a holy grail — “perfect, but unattainable.”

On Friday, Aug. 14, the first day California ordered rolling blackouts, Stem, an energy company based in the San Francisco Bay Area, delivered 50 megawatts — enough to power 20,000 homes — from batteries it had installed at businesses, local governments and other customers. Some of those devices were at the Orange County Sanitation District, which installed the batteries to reduce emissions by making it less reliant on natural gas when energy use peaks.

John Carrington, Stem’s chief executive, said his company would have provided even more electricity to the grid had it not been for state regulations that, among other things, prevent businesses from selling power from their batteries directly to other companies.

“We could have done two or three times more,” he said.

The California Independent System Operator, which manages about 80 percent of the state’s grid, has blamed the rolling blackouts on a confluence of unfortunate events, including extreme weather impacts on the grid that limited supply: A gas plant abruptly went offline, a lack of wind stilled thousands of turbines, and power plants in other states couldn’t export enough electricity. (On Thursday, the grid manager urged Californians to reduce electricity use over Labor Day weekend because temperatures are expected to be 10 to 20 degrees above normal.)

But in recent weeks it has become clear that California’s grid managers also made mistakes last month, highlighting the challenge of fixing California’s electric grid in real time, that were reminiscent of an energy crisis in 2000 and 2001 when millions of homes went dark and wholesale electricity prices soared.

Grid managers did not contact Gov. Gavin Newsom’s office until moments before it ordered a blackout on Aug. 14. Had it acted sooner, the governor could have called on homeowners and businesses to reduce electricity use, something he did two days later. He could have also called on the State Department of Water Resources to provide electricity from its hydroelectric plants.

Weather forecasters had warned about the heat wave for days. The agency could have developed a plan to harness the electricity in numerous batteries across the state that largely sat idle while grid managers and large utilities such as Pacific Gas & Electric scrounged around for more electricity.

That search culminated in frantic last-minute pleas from the California Public Utilities Commission to the California Solar and Storage Association. The commission asked the group to get its members to discharge batteries they managed for customers like the sanitation department into the grid. (Businesses and homeowners typically buy batteries with solar panels from companies like Stem and Sunrun, which manage the systems for their customers.)

“They were texting and emailing and calling us: ‘We need all of your battery customers giving us power,’” said Bernadette Del Chiaro, executive director of the solar and storage association. “It was in a very last-minute, herky-jerky way.”

At the time of blackouts on Aug. 14, battery power to the electric grid climbed to a peak of about 147 megawatts, illustrating how virtual power plants can rapidly scale, according to data from California I.S.O. After officials asked for more power the next day, that supply shot up to as much as 310 megawatts.

Had grid managers and regulators done a better job coordinating with battery managers, the devices could have supplied as much as 530 megawatts, Ms. Del Chiaro said. That supply would have exceeded the amount of electricity the grid lost when the natural gas plant, which grid managers have refused to identify, went offline.

Officials at California I.S.O. and the public utilities commission said they were working to determine the “root causes” of the crisis after the governor requested an investigation.

Grid managers and state officials have previously endorsed the use of batteries, using AI to adapt as they integrate them at scale. The utilities commission last week approved a proposal by Southern California Edison, which serves five million customers, to add 770 megawatts of energy storage in the second half of 2021, more than doubling its battery capacity.

And Mr. Zahurancik’s company, Fluence, is building a 400 megawatt-hour battery system at the site of an older natural gas power plant at the Alamitos Energy Center in Long Beach. Regulators this week also approved a plan to extend the life of the power plant, which was scheduled to close at the end of the year, to support the grid.

But regulations have been slow to catch up with the rapidly developing battery technology.

Regulators and utilities have not answered many of the legal and logistical questions that have limited how batteries owned by homeowners and businesses are used. How should battery owners be compensated for the electricity they provide to the grid? Can grid managers or utilities force batteries to discharge even if homeowners or businesses want to keep them charged up for their own use during blackouts?

During the recent blackouts, Ms. Del Chiaro said, commercial and industrial battery owners like Stem’s customers were compensated at the rates similar to those that are paid to businesses to not use power during periods of high electricity demand. But residential customers were not paid and acted “altruistically,” she said.

 

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Electricity prices rise more than double EU average in first half of 2021

Estonia energy prices 2021 show sharp electricity hikes versus the EU average, mixed natural gas trends, kWh tariffs on Nord Pool spiking, and VAT, taxes, and support measures shaping household bills.

 

Key Points

EU-high electricity growth, early gas dip, then Nord Pool spikes; taxes, VAT, and subsidies shaped energy bills.

✅ Electricity up 7% on year; EU average 2.8% in H1 2021.

✅ Gas fell 1% in H1; later spiked with global market.

✅ VAT, taxes, excise and aid impacted household costs.

 

Estonia saw one of the highest rates in growth of electricity prices in the first half of 2021, compared with the same period in key trends in 2020 across Europe. These figures were posted before the more recent, record level of electricity and natural gas prices; the latter actually dropped slightly in Estonia in the first half of the year.

While electricity prices rose 7 percent on year in the first half of 2021 in Estonia, the average for the EU as a whole, where energy prices drove inflation across the bloc, stood at 2.8 percent over the same period, BNS reports.

Hungary (€10 per 100 Kwh) and Bulgaria (€10.20 per 100 Kwh) saw the lowest electricity prices EU-wide, while at €31.9 per KWH, Germany's power prices posted the most expensive rate, while Denmark, Belgium and Ireland also had high prices, in excess of €25 per Kwh.

Slovenia saw the highest electricity price rise, at 15 percent, and even the United States' electricity prices saw their steepest rise in decades during the same era, while Estonia was in third place, joint with Romania at 7 percent as noted, and behind Poland (8 percent).

Lithuania, on the other hand, experienced the third highest electricity price fall over the first half of 2021, compared with the same period in 2020, at 6 percent, behind only Cyprus (7 percent) and the Netherlands (10 percent, largely due to a tax cut).

Urmas Reinsalu: VAT on electricity, gas and heating needs to be lowered
The EU average price of electricity was €21.9 percent per Kwh, with taxes and excise accounting for 39 percent of this, even as prices in Spain surged across the day-ahead market.

Estonia has also seen severe electricity price rises in the second half of the year so far, with records set and then promptly broken several times earlier in October, while an Irish electricity provider raised prices amid similar pressures, and a support package for low income households rolled out for the winter season (October to March next year). The price on the Nord Pool market as of €95.01 per Kwh; a day earlier it had stood at €66.21 per Kwh, while on October 19 the price was €140.68 per Kwh.

Gas prices
Natural gas prices to household, meanwhile, dropped in Estonia over the same period, at a sharper rate (1 percent) than the EU average (0.5 percent), according to Eurostat.

Gas prices across the EU were lowest in Lithuania (€2.8 per 100 Kwh) and highest in the Netherlands (€9.6 per KWH), while the highest growth was seen in Denmark (19 percent), in the first half of 2021.

Natural gas prices dropped in 20 member states, however, with the largest drop again coming in Lithuania (23 percent).

The average price of natural gas EU-side in the first half of 2021 was €6.4, and taxes and excise duties accounted on average for 36 percent of the total.

The second half of the year has seen steep gas price rises in Estonia, largely the result of increases on the world market, though European gas benchmarks later fell to pre-Ukraine war levels.

 

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Sustaining U.S. Nuclear Power And Decarbonization

Existing Nuclear Reactor Lifetime Extension sustains carbon-free electricity, supports deep decarbonization, and advances net zero climate goals by preserving the US nuclear fleet, stabilizing the grid, and complementing advanced reactors.

 

Key Points

Extending licenses keeps carbon-free nuclear online, stabilizes grid, and accelerates decarbonization toward net zero.

✅ Preserves 24/7 carbon-free baseload to meet climate targets

✅ Avoids emissions and replacement costs from premature retirements

✅ Complements advanced reactors; reduces capital and material needs

 

Nuclear power is the single largest source of carbon-free energy in the United States and currently provides nearly 20 percent of the nation’s electrical demand. As a result, many analyses have investigated the potential of future nuclear energy contributions in addressing climate change and investing in carbon-free electricity across the sector. However, few assess the value of existing nuclear power reactors.

Research led by Pacific Northwest National Laboratory (PNNL) Earth scientist Son H. Kim, with the Joint Global Change Research Institute (JGCRI), a partnership between PNNL and the University of Maryland, has added insight to the scarce literature and is the first to evaluate nuclear energy for meeting deep decarbonization goals amid rising credit risks for nuclear power identified by Moody's. Kim sought to answer the question: How much do our existing nuclear reactors contribute to the mission of meeting the country’s climate goals, both now and if their operating licenses were extended?

As the world races to discover solutions for reaching net zero as part of the global energy transition now underway, Kim’s report quantifies the economic value of bringing the existing nuclear fleet into the year 2100. It outlines its significant contributions to limiting global warming.

Plants slated to close by 2050 could be among the most important players in a challenge requiring all available carbon-free technology solutions—emerging and existing—alongside renewable electricity in many regions, the report finds. New nuclear technology also has a part to play, and its contributions could be boosted by driving down construction costs.  

“Even modest reductions in capital costs could bring big climate benefits,” said Kim. “Significant effort has been incorporated into the design of advanced reactors to reduce the use of all materials in general, such as concrete and steel because that directly translates into reduced costs and carbon emissions.”

Nuclear power reactors face an uncertain future, and some utilities face investor pressure to release climate reports as well.
The nuclear power fleet in the United States consists of 93 operating reactors across 28 states. Most of these plants were constructed and deployed between 1970-1990. Half of the fleet has outlived its original operating license lifetime of 40 years. While most reactors have had their licenses renewed for an additional 20 years, and some for another 20, the total number of reactors that will receive a lifetime extension to operate a full 80 years from deployment is uncertain.

Other countries also rely on nuclear energy. In France, for example, nuclear energy provides 70 percent of the country’s power supply. They and other countries must also consider extending the lifetime, retiring, or building new, modern reactors while navigating Canadian climate policy implications for electricity grids. However, the U.S. faces the potential retirement of many reactors in a short period—this could have a far stronger impact than the staggered closures other countries may experience.

“Our existing nuclear power plants are aging, and with their current 60-year lifetimes, nearly all of them will be gone by 2050. It’s ironic. We have a net zero goal to reach by 2050, yet our single largest source of carbon-free electricity is at risk of closure, as seen in New Zealand's electricity transition debates,“ said Kim.

 

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How Canada can capitalize on U.S. auto sector's abrupt pivot to electric vehicles

Canadian EV Manufacturing is accelerating with GM, Ford, and Project Arrow, integrating cross-border supply chains, battery production, rare-earths like lithium and cobalt, autonomous tech, and home charging to drive clean mobility and decarbonization.

 

Key Points

Canadian EV manufacturing spans electric and autonomous vehicles, domestic batteries, and integrated US-Canada trade.

✅ GM and Ford retool plants for EVs and autonomous production

✅ Project Arrow showcases Canadian zero-emission supply capabilities

✅ Lithium, cobalt, and battery hubs target cross-border resilience

 

The storied North American automotive industry, the ultimate showcase of Canada’s high-tensile trade ties with the United States and emerging Canada-U.S. collaboration on EVs momentum, is about to navigate a dramatic hairpin turn.

But as the Big Three veer into the all-electric, autonomous era, some Canadians want to seize the moment and take the wheel.

“There’s a long shadow between the promise and the execution, but all the pieces are there,” says Flavio Volpe, president of the Automotive Parts Manufacturers’ Association.

“We went from a marriage on the rocks to one that both partners are committed to. It could be the best second chapter ever.”

Volpe is referring specifically to GM, which announced late last month an ambitious plan to convert its entire portfolio of vehicles to an all-electric platform by 2035.

But that decision is just part of a cascading transformation across the industry, marking an EV inflection point with existential ramifications for one of the most tightly integrated cross-border manufacturing and supply-chain relationships in the world.

China is already working hard to become the “source of a new way” to power vehicles, President Joe Biden warned last week.

“We just have to step up.”

Canada has both the resources and expertise to do the same, says Volpe, whose ambitious Project Arrow concept — a homegrown zero-emissions vehicle named for the 1950s-era Avro interceptor jet — is designed to showcase exactly that, as recent EV assembly deals in Canada underscore.

“We’re going to prove to the market, we’re going to prove to the (manufacturers) around the planet, that everything that goes into your zero-emission vehicle can be made or sourced here in Canada,” he says.

“If somebody wants to bring what we did over the line and make 100,000 of them a year, I’ll hand it to them.”

GM earned the ire of Canadian auto workers in 2018 by announcing the closure of its assembly plant in Oshawa, Ont. It later resurrected the facility with a $170-million investment to retool it for autonomous vehicles.

“It was, ‘You closed Oshawa, how dare you?’ And I was one of the ‘How dare you’ people,” Volpe says.

“Well, now that they’ve reopened Oshawa, you sit there and you open your eyes to the commitment that General Motors made.”

Ford, too, has entered the fray, promising $1.8 billion to retool its sprawling landmark facility in Oakville, Ont., to build EVs.

It’s a leap of faith of sorts, considering what market experts say is ongoing consumer doubt about EVs and EV supply shortages that drive wait times.

“Range anxiety” — the persistent fear of a depleted battery at the side of the road — remains a major concern, even though it’s less of a problem than most people think.

Consulting firm Deloitte Canada, which has been tracking automotive consumer trends for more than a decade, found three-quarters of future EV buyers it surveyed planned to charge their vehicles at home overnight.

“The difference between what is a perceived issue in a consumer’s mind and what is an actual issue is actually quite negligible,” Ryan Robinson, Deloitte’s automotive research leader, says in an interview.

“It’s still an issue, full stop, and that’s something that the industry is going to have to contend with.”

So, too, is price, especially with the end of the COVID-19 pandemic still a long way off. Deloitte’s latest survey, released last month, found 45 per cent of future buyers in Canada hope to spend less than $35,000 — a tall order when most base electric-vehicle models hover between $40,000 and $45,000.

“You put all of that together and there’s still, despite the electric-car revolution hype, some major challenges that a lot of stakeholders that touch the automotive industry face,” Robinson says.

“It’s not just government, it’s not just automakers, but there are a variety of stakeholders that have a role to play in making sure that Canadians are ready to make the transition over to electric mobility.”

With protectionism no longer a dirty word in the United States and Biden promising to prioritize American workers and suppliers, the Canadian government’s job remains the same as it ever was: making sure the U.S. understands Canada’s mission-critical role in its own economic priorities.

“We’re both going to be better off on both sides of the border, as we have been in the past, if we orient ourselves toward this global competition as one force,” says Gerald Butts, vice-chairman of the political-risk consultancy Eurasia Group and a former principal secretary to Prime Minister Justin Trudeau.

“It served us extraordinarily well in the past … and I have no reason to believe it won’t serve us well in the future.”

Last month, GM announced a billion-dollar plan to build its new all-electric BrightDrop EV600 van in Ingersoll, Ont., at Canada’s first large-scale EV manufacturing plant for delivery vehicles.

That investment, Volpe says, assumes Canada will take the steps necessary to help build a homegrown battery industry — with projects such as a new Niagara-region battery plant pointing the way — drawing on the country’s rare-earth resources like lithium and cobalt that are waiting to be extracted in northern Ontario, Quebec and elsewhere.

Given that the EV industry is still in his infancy, the free market alone won’t be enough to ensure those resources can be extracted and developed, he says.

“General Motors made a billion-dollar bet on Canada because it’s going to assume that the Canadian government — this one or the next one — is going to commit” to building that business.

Such an investment would pay dividends well beyond the auto sector, considering the federal Liberal government’s commitment to lowering greenhouse gas-emissions, including a 2035 EV mandate, and meeting targets set out in the Paris climate accord.

“If you make investments in renewable energy and utility storage using battery technology, you can build an industry at scale that the auto industry can borrow,” Volpe says.

Major manufacturing, retail and office facilities would be able to use that technology to help “shave the peak” off Canada’s GHG emissions and achieve those targets, all the while paving the way for a self-sufficient electric-vehicle industry.

“You’d be investing in the exact same technology you’d use in a car.”

There’s one problem, says Robinson: the lithium-ion batteries on roads right now might not be where the industry ultimately lands.

“We’re not done with with battery technology,” Robinson says. “What you don’t want to do is invest in a technology that is that is rapidly evolving, and could potentially become obsolete going forward.”

Fuel cells — energy-efficient, hydrogen-powered units that work like batteries, but without the need for constant recharging — continue to be part of the conversation, he adds.

“The amount of investment is huge, and you want to be sure that you’re making the right decision, so you don’t find yourself behind the curve just as all that capacity is coming online.”

 

 

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