NYC pulls plug on DC service

By International Herald Tribune


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The city that inventor Thomas Edison electrified 125 years ago has completed the transition from direct to alternating current, helping to erase the vestiges of a feud between giants of invention.

The Consolidated Edison utility pulled the plug on direct current service.

The change means that Con Ed now exclusively uses the alternating current system invented by Nikola Tesla. The utility is named for Edison, whose Pearl Street Station in Manhattan was the first U.S. central electrical power plant, serving 59 customers with direct current beginning in 1882.

In the so-called "war of currents," Edison feuded with Tesla and George Westinghouse over which transmission method to adopt — even going so far as to publicly electrocute animals in the hopes of showing AC was too dangerous.

Alternating current proved superior as transformers allowed electricity to travel over long-distance wires. As AC gained prevalence over DC across the world, Con Ed froze the development of the DC system in 1928 but continued to supply New York's major DC customers with the existing system.

In January 1998, Con Ed began to eliminate DC service. At that time, there were more than 4,600 DC customers. By last year, there were only 60.

Con Ed spokesman Robert McGee said some of the city's elevators still operate with DC using rectifiers that convert the utility's AC service.

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FortisAlberta Takes Necessary Precautions to Provide Electricity Service for Alberta

FortisAlberta COVID-19 response delivers safe electricity distribution across Alberta, with remote monitoring, 24/7 support, outage alerts, dispersed crews, and business continuity measures to sustain essential services for customers and communities.

 

Key Points

Plan ensuring reliable electricity in Alberta through 24/7 support, remote monitoring, outage alerts, and dispersed crews.

✅ 24/7 customer support via 310-WIRE and mobile app

✅ Remote monitoring and rapid outage restoration

✅ Dispersed crews in 50 communities for faster response

 

As the COVID-19 pandemic continues to evolve in Alberta (and around the world), FortisAlberta is taking the necessary actions and precautions informed by utility disaster planning to protect the health and well-being of its employees and to provide electricity service to its customers. FortisAlberta serves more than half a million customers with the electricity they depend on to take care of their families and community members throughout our province.

"We recognize these are challenging times as while most Albertans are asked to stay home others continue to work in the community to provide essential services, including utility workers in Ontario demonstrating support efforts. As your electricity distribution provider, please be assured you can count on us to do what we do best – provide our customers with safe and reliable electricity service wherever and whenever they need it," says Michael Mosher, FortisAlberta President and CEO.

FortisAlberta is proud to be a part of the communities it serves and commits to keeping the lights on for its customers. The company is providing a full range of services for its customers and has instilled best practices within critical parts of its business. The company's control centre continues to remotely monitor, control, and restore, where possible, the delivery of power across the entire province, including during events such as an Alberta grid alert that stress the system. Early in March, FortisAlberta implemented its business continuity plan and the company remains fully accessible to customers 24/7 by phone at 310-WIRE (9473) or through its mobile app where customers can report outages online or view details of an outage. Customers can also sign up for outage alerts to their mobile phone and/or email address to let them know if an outage does occur.

FortisAlberta's power line employees are geographically dispersed across 50 different communities so they can quickly address any issues that may arise. The company has implemented work from home measures and isolation best practices, and is planning for potential on-site lockdowns where necessary to ensure no disruption to customers.

FortisAlberta will continue to remain in close communication with its stakeholders to provide updates to customers and with industry associations to share guidance specific to the electricity sector, including insights on the evolving U.S. grid response to COVID-19 from peer utilities. FortisAlberta will also continue to invest in and empower its communities by contributing to organizations that offer programs and services aligned with the greatest needs in the communities it serves.

With the Alberta Government's recent announcement to provide relief to eligible Albertans by deferring electricity and gas charges for up to 90 days, similar to some B.C. relief measures being implemented, FortisAlberta is committed to working with stakeholders and retail partners to ensure this option is available to customers quickly and efficiently, and to learn from initiatives like the Hydro One relief fund that support customers.

 

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Energy Ministry may lower coal production target as Chinese demand falls

Indonesia Coal Production Cuts reflect weaker China demand, COVID-19 impacts, falling HBA reference prices, and DMO sales to PLN, pressuring thermal coal output, miner budgets, and investment plans under the 2020 RKAB.

 

Key Points

Planned 2020 coal output reductions from China demand slump, lower HBA prices, and DMO constraints impacting miners.

✅ China demand drop reduces exports and thermal coal shipments.

✅ HBA reference price decline pressures margins and cash flow.

✅ DMO sales to PLN limit revenue; investment plans may slow.

 

The Energy and Mineral Resources (ESDM) Ministry is considering lowering the coal production target this year as demand from China has shown a significant decline, with China power demand drops reported, since the start of the outbreak of the novel coronavirus in the country late last year, a senior ministry official has said.

The ministry’s coal and mineral director general Bambang Gatot Ariyono said in Jakarta on March 12 that the decline in the demand had also caused a sharp drop in coal prices on the world market, and China's plan to reduce coal power has further weighed on sentiment, which could cause the country’s miners to reduce their production.

The 2020 minerals and coal mining program and budget (RKAB) has set a current production goal of 550 million tons of coal, a 10 percent increase from last year’s target. As of March 6, 94.7 million tons of coal had been mined in the country in the year.

“With the existing demand, revision to this year’s production is almost certain,” he said, adding that the drop in demand had also caused a decline in coal prices.

Indonesia’s thermal coal reference price (HBA) fell by 26 percent year-on-year to US$67.08 per metric ton in March, according to a Standards & Poor press release on March 5.  At home, the coal price is also unattractive for local producers. Under the domestic market obligation (DMO) policy, miners are required to sell a quarter of their production to state-owned electricity company PLN at a government-set price, even as imported coal volumes rise in some markets. This year’s coal reference price is $70 per metric ton, far below the internal prices before the coronavirus outbreak hit China.

The ministry’s expert staff member Irwandy Arif said China had reduced its coal demand by 200,000 tons so far, as six of its coal-fired power plants had suspended operation due to the significant drop in electricity demand. Many factories in the country were closed as the government tried to halt the spread of the new coronavirus, which caused the decline in energy demand and created electric power woes for international supply chains.

“At present, all mines in Indonesia are still operating normally, while India is rationing coal supplies amid surging electricity demand. But we have to see what will happen in June,” he said.

The ministry predicted that the low demand would also result in a decline in coal mining investment, as clean energy investment has slipped across many developing nations.

The ministry set a $7.6 billion investment target for the mining sector this year, up from $6.17 billion last year, even as Israel reduces coal use in its power sector, which may influence regional demand. The year’s total investment realization was $192 million as of March 6, or around 2.5 percent of the annual target. 

 

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Electricity demand set to reduce if UK workforce self-isolates

UK Energy Networks Coronavirus Contingency outlines ESO's lockdown electricity demand forecast, reduced industrial and commercial load, rising domestic use, Ofgem guidance needs, grid resilience, control rooms, mutual aid, and backup centers.

 

Key Points

A coordinated plan with ESO forecasts, safeguards, and mutual aid to keep power and gas services during a lockdown.

✅ ESO forecasts lower industrial use, higher domestic demand

✅ Control rooms protected; backup sites and cross-trained staff

✅ Mutual aid and Ofgem coordination bolster grid resilience

 

National Grid ESO is predicting a reduction in electricity demand, consistent with residential use trends observed during the pandemic, in the case of the coronavirus spread prompting a lockdown across the country.

Its analysis shows the reduction in commercial and industrial use would outweigh an upsurge in domestic demand, mirroring Ontario demand data seen as people stayed home, according to similar analyses.

The prediction was included in an update from the Energy Networks Association (ENA), in which it sought to reassure the public that contingency plans are in place, reflecting utility disaster planning across electric and gas networks, to ensure services are unaffected by the coronavirus spread.

The body, which represents the UK's electricity and gas network companies, said "robust measures" had been put in place to protect control rooms and contact centres, similar to staff lockdown protocols considered by other system operators, to maintain resilience. To provide additional resilience, engineers have been trained across multiple disciplines and backup centres exist should operations need to be moved if, for example, deep cleaning is required, the ENA said.

Networks also have industry-wide mutual aid arrangements, similar to grid response measures outlined in the U.S., for people and the equipment needed to keep gas and electricity flowing.

ENA chief executive, David Smith, said, echoing system reliability assurances from other markets: "The UK's electricity and gas network is one of the most reliable in the world and network operators are working with the authorities to ensure that their contingency plans are reviewed and delivered in accordance with the latest expert advice. We are following this advice closely and reassuring customers that energy networks are continuing to operate as normal for the public."

Utility Week spoke to a senior figure at one of the networks who reiterated the robust measures in place to keep the lights on, even as grid alerts elsewhere highlight the importance of contingency planning. However, they pleaded for more clarity from Ofgem and government on how its workers will be treated if the coronavirus spread becomes a pandemic in the UK.

 

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Canadian power crews head to Irma-hit Florida to help restore service

Canadian Power Crews Aid Florida after Hurricane Irma, supporting power restoration for Tampa Electric and Florida Power & Light. Hydro One and Nova Scotia Power teams provide mutual aid to speed outage repairs across communities.

 

Key Points

Mutual aid effort sending Canadian utility crews to restore power and repair outages in Florida after Hurricane Irma.

✅ Hydro One and Nova Scotia Power deploy line technicians

✅ Support for Tampa Electric and Florida Power & Light

✅ Goal: rapid power restoration and outage repairs statewide

 

Hundreds of Canadian power crews are heading to Florida to help restore power to millions of people affected by Hurricane Irma.

Two dozen Nova Scotia Power employees were en route Tampa on Tuesday morning. An additional 175 Hydro One employees from across Ontario are also heading south. Tuesday to assist after receiving a request for assistance from Tampa Electric.

Nearly 7½ million customers across five states were without power Tuesday morning as Irma — now a tropical storm — continued inland, while a power outage update from the Carolinas underscored the regional strain.

In an update On Tuesday, Florida Power & Light said its "army" of crews had already restored power to 40 per cent of the five million customers affected by Irma in the first 24 hours.

FPL said it expects to have power restored in nearly all of the eastern half of the state by the end of this coming weekend. Almost everyone should have power restored by the end of day on Sept. 22, except for areas still under water.Jason Cochrane took a flight from Halifax Stanfield International Airport along with 19 other NSP power line technicians, two supervisors and a restoration team lead, drawing on lessons from the Maritime Link first power project between Newfoundland and Nova Scotia. "It's different infrastructure than what we have to a certain extent, so there'll be a bit of a learning curve there as well," Cochrane said. "But we'll be integrated into their workforce, so we'll be assisting them to get everything put back together."

The NSP team will join 86 other Nova Scotians from their parent company, Emera, who are also heading to Tampa. Halifax-based Emera, whose regional projects include the Maritime Link, owns a subsidiary in Tampa.

"We're going to be doing anything that we can to help Tampa Electric get their customers back online," said NSP spokesperson Tiffany Chase. "We know there's been significant damage to their system as a result of that severe storm and so anything that our team can do to assist them, we want to do down in Tampa."

Crews have been told to expect to be on the ground in the U.S. for two weeks, but that could change as they get a better idea of what they're dealing with.

'It's neat to have an opportunity like this to go to another country and to help out.'- Jason Cochrane, power line technician

"It's neat to have an opportunity like this to go to another country and to help out and to get the power back on safely," said Cochrane.

Chase said she doesn't know how much the effort will cost but it will be covered by Tampa Electric. She also said Nova Scotia Power will pull its crews back if severe weather heads toward Atlantic Canada, as utilities nationwide work to adapt to climate change in their planning.

 

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Offshore wind is set to become a $1 trillion business

Offshore wind power accelerates low-carbon electrification, leveraging floating turbines, high capacity factors, HVDC transmission, and hydrogen production to decarbonize grids, cut CO2, and deliver competitive, reliable renewable energy near demand centers.

 

Key Points

Offshore wind power uses offshore turbines to deliver low-carbon electricity with high capacity factors and falling costs.

✅ Sea-based wind farms with 40-50% capacity factors

✅ Floating turbines unlock deep-water, far-shore resources

✅ Enables hydrogen production and strengthens grid reliability

 

The need for affordable low-carbon technologies is greater than ever

Global energy-related CO2 emissions reached a historic high in 2018, driven by an increase in coal use in the power sector. Despite impressive gains for renewables, fossil fuels still account for nearly two-thirds of electricity generation, the same share as 20 years ago. There are signs of a shift, with increasing pledges to decarbonise economies and tackle air pollution, and with World Bank support helping developing countries scale wind, but action needs to accelerate to meet sustainable energy goals. As electrification of the global energy system continues, the need for clean and affordable low-carbon technologies to produce this electricity is more pressing than ever. This World Energy Outlook special report offers a deep dive on a technology that today has a total capacity of 23 GW (80% of it in Europe) and accounts for only 0.3% of global electricity generation, but has the potential to become a mainstay of the world's power supply. The report provides the most comprehensive analysis to date of the global outlook for offshore wind, its contributions to electricity systems and its role in clean energy transitions.

 

The offshore wind market has been gaining momentum

The global offshore wind market grew nearly 30% per year between 2010 and 2018, benefitting from rapid technology improvements. Over the next five years, about 150 new offshore wind projects are scheduled to be completed around the world, pointing to an increasing role for offshore wind in power supplies. Europe has fostered the technology's development, led by the UK offshore wind sector alongside Germany and Denmark. The United Kingdom and Germany currently have the largest offshore wind capacity in operation, while Denmark produced 15% of its electricity from offshore wind in 2018. China added more capacity than any other country in 2018.

 

The untapped potential of offshore wind is vast

The best offshore wind sites could supply more than the total amount of electricity consumed worldwide today. And that would involve tapping only the sites close to shores. The IEA initiated a new geospatial analysis for this report to assess offshore wind technical potential country by country. The analysis was based on the latest global weather data on wind speed and quality while factoring in the newest turbine designs. Offshore wind's technical potential is 36 000 TWh per year for installations in water less than 60 metres deep and within 60 km from shore. Global electricity demand is currently 23 000 TWh. Moving further from shore and into deeper waters, floating turbines could unlock enough potential to meet the world's total electricity demand 11 times over in 2040. Our new geospatial analysis indicates that offshore wind alone could meet several times electricity demand in a number of countries, including in Europe, the United States and Japan. The industry is adapting various floating foundation technologies that have already been proven in the oil and gas sector. The first projects are under development and look to prove the feasibility and cost-effectiveness of floating offshore wind technologies.

 

Offshore wind's attributes are very promising for power systems

New offshore wind projects have capacity factors of 40-50%, as larger turbines and other technology improvements are helping to make the most of available wind resources. At these levels, offshore wind matches the capacity factors of gas- and coal-fired power plants in some regions – though offshore wind is not available at all times. Its capacity factors exceed those of onshore wind and are about double those of solar PV. Offshore wind output varies according to the strength of the wind, but its hourly variability is lower than that of solar PV. Offshore wind typically fluctuates within a narrower band, up to 20% from hour to hour, than solar PV, which varies up to 40%.

Offshore wind's high capacity factors and lower variability make its system value comparable to baseload technologies, placing it in a category of its own – a variable baseload technology. Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind's system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV. Offshore wind also contributes to electricity security, with its high availability and seasonality patterns it is able to make a stronger contribution to system needs than other variable renewables. In doing so, offshore wind contributes to reducing CO2 and air pollutant emissions while also lowering the need for investment in dispatchable power plants. Offshore wind also has the advantage of avoiding many land use and social acceptance issues that other variable renewables are facing.

 

Offshore wind is on track to be a competitive source of electricity

Offshore wind is set to be competitive with fossil fuels within the next decade, as well as with other renewables including solar PV. The cost of offshore wind is declining and is set to fall further. Financing costs account for 35% to 50% of overall generation cost, and supportive policy frameworks are now enabling projects to secure low cost financing in Europe, with zero-subsidy tenders being awarded. Technology costs are also falling. The levelised cost of electricity produced by offshore wind is projected to decline by nearly 60% by 2040. Combined with its relatively high value to the system, this will make offshore wind one of the most competitive sources of electricity. In Europe, recent auctions indicate that offshore wind will soon beat new natural gas-fired capacity on cost and be on a par with solar PV and onshore wind. In China, offshore wind is set to become competitive with new coal-fired capacity around 2030 and be on par with solar PV and onshore wind. In the United States, recent project proposals indicate that offshore wind will soon be an affordable option, even as the 1 GW timeline continues to evolve, with potential to serve demand centres along the country's east coast.

Innovation is delivering deep cost reductions in offshore wind, and transmission costs will become increasingly important. The average upfront cost to build a 1 gigawatt offshore wind project, including transmission, was over $4 billion in 2018, but the cost is set to drop by more than 40% over the next decade. This overall decline is driven by a 60% reduction in the costs of turbines, foundations and their installation. Transmission accounts for around one-quarter of total offshore wind costs today, but its share in total costs is set to increase to about one-half as new projects move further from shore. Innovation in transmission, for example through work to expand the limits of direct current technologies, will be essential to support new projects without raising their overall costs.

 

Offshore wind is set to become a $1 trillion business

Offshore wind power capacity is set to increase by at least 15-fold worldwide by 2040, becoming a $1 trillion business. Under current investment plans and policies, the global offshore wind market is set to expand by 13% per year, reflecting its growth despite Covid-19 in recent years, passing 20 GW of additions per year by 2030. This will require capital spending of $840 billion over the next two decades, almost matching that for natural gas-fired or coal-fired capacity. Achieving global climate and sustainability goals would require faster growth: capacity additions would need to approach 40 GW per year in the 2030s, pushing cumulative investment to over $1.2 trillion. 

The promising outlook for offshore wind is underpinned by policy support in an increasing number of regions. Several European North Seas countries – including the United Kingdom, Germany, the Netherlands and Denmark – have policy targets supporting offshore wind. Although a relative newcomer to the technology, China is quickly building up its offshore wind industry, aiming to develop a project pipeline of 10 GW by 2020. In the United States, state-level targets and federal incentives are set to kick-start the U.S. offshore wind surge in the coming years. Additionally, policy targets are in place and projects under development in Korea, Japan, Chinese Taipei and Viet Nam.

 The synergies between offshore wind and offshore oil and gas activities provide new market opportunities. Since offshore energy operations share technologies and elements of their supply chains, oil and gas companies started investing in offshore wind projects many years ago. We estimate that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, have significant synergies with the offshore oil and gas sector. That translates into a market opportunity of $400 billion or more in Europe and China over the next two decades. The construction of foundations and subsea structures offers potential crossover business, as do practices related to the maintenance and inspection of platforms. In addition to these opportunities, offshore oil and gas platforms require electricity that is often supplied by gas turbines or diesel engines, but that could be provided by nearby wind farms, thereby reducing CO2 emissions, air pollutants and costs.

 

Offshore wind can accelerate clean energy transitions

Offshore wind can help drive energy transitions by decarbonising electricity and by producing low-carbon fuels. Over the next two decades, its expansion could avoid between 5 billion and 7 billion tonnes of CO2 emissions from the power sector globally, while also reducing air pollution and enhancing energy security by reducing reliance on imported fuels. The European Union is poised to continue leading the wind energy at sea in Europe industry in support of its climate goals: its offshore wind capacity is set to increase by at least fourfold by 2030. This growth puts offshore wind on track to become the European Union's largest source of electricity in the 2040s. Beyond electricity, offshore wind's high capacity factors and falling costs makes it a good match to produce low-carbon hydrogen, a versatile product that could help decarbonise the buildings sector and some of the hardest to abate activities in industry and transport. For example, a 1 gigawatt offshore wind project could produce enough low-carbon hydrogen to heat about 250 000 homes. Rising demand for low-carbon hydrogen could also dramatically increase the market potential for offshore wind. Europe is looking to develop offshore "hubs" for producing electricity and clean hydrogen from offshore wind.

 

It's not all smooth sailing

Offshore wind faces several challenges that could slow its growth in established and emerging markets, but policy makers and regulators can clear the path ahead. Developing efficient supply chains is crucial for the offshore wind industry to deliver low-cost projects. Doing so is likely to call for multibillion-dollar investments in ever-larger support vessels and construction equipment. Such investment is especially difficult in the face of uncertainty. Governments can facilitate investment of this kind by establishing a long-term vision for offshore wind and by drawing on U.K. policy lessons to define the measures to be taken to help make that vision a reality. Long-term clarity would also enable effective system integration of offshore wind, including system planning to ensure reliability during periods of low wind availability.

The success of offshore wind depends on developing onshore grid infrastructure. Whether the responsibility for developing offshore transmission lies with project developers or transmission system operators, regulations should encourage efficient planning and design practices that support the long-term vision for offshore wind. Those regulations should recognise that the development of onshore grid infrastructure is essential to the efficient integration of power production from offshore wind. Without appropriate grid reinforcements and expansion, there is a risk of large amounts of offshore wind power going unused, and opportunities for further expansion could be stifled. Development could also be slowed by marine planning practices, regulations for awarding development rights and public acceptance issues.

The future of offshore wind looks bright but hinges on the right policies

The outlook for offshore wind is very positive as efforts to decarbonise and reduce local pollution accelerate. While offshore wind provides just 0.3% of global electricity supply today, it has vast potential around the world and an important role to play in the broader energy system. Offshore wind can drive down CO2 emissions and air pollutants from electricity generation. It can also do so in other sectors through the production of clean hydrogen and related fuels. The high system value of offshore wind offers advantages that make a strong case for its role alongside other renewables and low-carbon technologies. Government policies will continue to play a critical role in the future of offshore wind and  the overall pace of clean energy transitions around the world.

 

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Atlantic Canadians less charged up to buy electric vehicle than rest of Canada

Atlantic Canada EV adoption lags, a new poll finds, as fewer buyers consider electric vehicles amid limited charging infrastructure, lower provincial rebates, and affordability pressures in Nova Scotia and Newfoundland compared to B.C. and Quebec.

 

Key Points

Atlantic Canada EV adoption reflects demand, shaped by rebates, charging access, costs, and the regional energy mix.

✅ Poll shows lowest purchase intent in Atlantic Canada

✅ Lack of rebates and charging slows EV consideration

✅ Income and energy mix affect affordability and benefits

 

Atlantic Canadians are the least likely to buy a car, truck or SUV in the next year and the most skittish about going electric, according to a new poll. 

Only 31 per cent of Nova Scotians are looking at buying a new or used vehicle before December 2021 rolls around. And just 13 per cent of Newfoundlanders who are planning to buy are considering an electric vehicle. Both those numbers are the lowest in the country. Still, 47 per cent of Nova Scotians considering buying in the next year are thinking about electric options, according to the numbers gathered online by Logit Group and analyzed by Halifax-based Narrative Research. That compares to 41 per cent of Canadians contemplating a vehicle purchase within the next year, with 54 per cent of them considering going electric. 

“There’s still a high level of interest,” said Margaret Chapman, chief operating officer at Narrative Research.  

“I think half of people who are thinking about buying a vehicle thinking about electric is pretty significant. But I think it’s a little lower in Atlantic Canada compared to other parts of the country probably because the infrastructure isn’t quite what it might be elsewhere. And I think also it’s the availability of vehicles as well. Maybe it just hasn’t quite caught on here to the extent that it might have in, say, Ontario or B.C., where the highest level of interest is.” 


Provincial rebates
Provincial rebates also serve to create more interest, she said, citing New Brunswick's rebate program as an example in the region. 

“There’s a $7,500 rebate on top of the $5,000 you get from the feds in B.C. But in Nova Scotia there’s no provincial rebate,” Chapman said. “So I think that kind of thing actually is significant in whether you’re interested in buying an electric vehicle or not.” 

The survey was conducted online Nov. 11–13 with 1,231 Canadian adults. 

Of the people across Canada who said they were not considering an electric vehicle purchase, 55 per cent said a provincial rebate would make them more likely to consider one, she said.  

In Nova Scotia, that number drops to 43 per cent. 

Nova Scotia families have the lowest median after-tax income in the country, according to numbers released earlier this year.  

The national median in 2018 was $61,400, according to Statistics Canada. Nova Scotia was at the bottom of the pack with $52,200, up from $51,400 in 2017. 

So big price tags on electric vehicles might put them out of reach for many Nova Scotians, and a recent cost-focused survey found similar concerns nationwide. 

“I think it’s probably that combination of cost and infrastructure,” Chapman said. 

“But you saw this week in the financial update from the federal government that they’re putting $150 million into new charging station, so were some of that cash to be spread in Atlantic Canada, I’m sure there would be an increase in interest … The more charging stations around you see, you think ‘Alright, it might not be so hard to ensure that I don’t run out of power for my car.’ All of that stuff I think will start to pick up. But right now it is a little bit lagging in Atlantic Canada, and in Labrador infrastructure still lags despite a government push in N.L. to expand EVs.” 


'Simple dollars and cents'
The lack of a provincial government rebate here for electric vehicles definitely factors into the equation, said Sean O’Regan, president and chief executive officer of O'Regan's Automotive Group.  

“Where you see the highest adoption are in the provinces where there are large government rebates,” he said. “It’s a simple dollars and cents (thing). In Quebec, when you combine the rebates it’s up to over $10,000, if not $12,000, towards the car. If you can get that kind of a rebate on a car, I don’t know that it would matter much what it was – it would help sell it.” 

A lot of people who want to buy electric cars are trying to make a conscious decision about the environment, O’Regan said. 

While Nova Scotia Power is moving towards renewable energy, he points out that much of our electricity still comes from burning coal and other fossil fuels, and N.L. lags in energy efficiency as the region works to improve.  

“So the power that you get is not necessarily the cleanest of power,” O’Regan said. “The green advantage is not the same (in Nova Scotia as it is in provinces that produce a lot of hydro power).” 

Compared to five years ago, the charging infrastructure here is a lot better, he said. But it doesn’t compare well to provinces including Quebec and B.C., though Newfoundland recently completed its first fast-charging network for electric car owners. 

“Certainly (with) electric cars – we're selling more and more and more of them,” O'Regan said, noting the per centage would be in the single digits of his overall sales. “But you're starting from zero a few years ago.” 

The highest number of people looking at buying electric cars was in B.C., with 57 per cent of those looking at buying a car saying they’d go electric, and even in southern Alberta interest is growing; like Bob Dylan in 1965 at the Newport Folk Festival.  

“The trends move from west to east across Canada,” said Jeff Farwell, chief executive officer of the All EV Canada electric car store in Burnside.  

“I would use the example of the craft beer market. It started in B.C. about 15 years before it finally went crazy in Nova Scotia. And if you look at Vancouver right now there’s (electric vehicles) everywhere.” 


Expectations high
Farwell expects electric vehicle sales to take off faster in Atlantic Canada than the craft beer market. “A lot faster.” 

His company also sells used electric vehicles in Prince Edward Island and is making moves to set up in Moncton, N.B. 

He’s been talking to Nova Scotia’s Department of Energy and Mines about creating rebates here for new and used electric vehicles. 

 “I guess they’re interested, but nothing’s happened,” Farwell said.  

Electric vehicles require “a bit of a lifestyle change,” he said. 

“The misconception is it takes a lot longer to charge a vehicle if it’s electric and gas only takes me 10 minutes to fill up at the gas station,” Farwell said.  

“The reality is when I go home at night, I plug my vehicle in,” he said. “I get up in the morning and I unplug it and I never have to think about it. It takes two seconds.”  
 

 

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