Third exec at Enron pleads guilty

By San Francisco Chronicle


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The Enron Corp. energy trader who devised the notorious "Death Star" scheme to bill California for fictitious electricity pleaded guilty in a San Francisco court to a federal fraud charge and admitted plotting to manipulate the market during the state's energy crisis.

John Forney, 42, of Upper Arlington, Ohio, is the third former Enron executive to admit lawbreaking during the 2000-01 power shortages and price spikes that led to rolling blackouts and multibillion-dollar rate increases. He faces up to five years in prison.

Timothy Belden, Forney's former boss at Enron's West Coast power trading office in Portland, and Jeffrey Richter, another top Enron trader, are awaiting sentencing for fraud. Both talked to federal agents about Forney and identified him as a chief strategist, according to court documents.

"We have now obtained convictions of the top three Enron executives most directly responsible for manipulating the energy markets in California at a time unique in our history, when the lights were going off and the grid was in danger of shutting down,'' said Kevin Ryan, U.S. attorney in San Francisco. "These executives will now be required to help obtain restitution for the same victims they defrauded, namely the citizens of California and the other Western states."

But California has had little success recouping energy overcharges for its consumers, largely because of limits on reimbursement imposed by the Federal Energy Regulatory Commission.

State Attorney General Bill Lockyer sued Enron in June for damages allegedly caused by commodities fraud and unfair competition. Forney's plea agreement requires him to cooperate with Lockyer and with federal prosecutors looking into Enron and other companies.

"We are obviously interested in sitting down and having a good heart-to-heart with Mr. Forney to see what he may have to add to our body of evidence,'' said Lockyer spokesman Tom Dresslar.

Forney's attorney, Edwin Prather, said the plea agreement was "an opportunity for John to help right the wrongs that he helped create'' and to help the government in "understanding the bigger problem of misdeeds of the energy industry."

He said Forney had nothing to do with the case against former Enron Chairman Kenneth Lay, indicted last month on fraud charges connected to the Houston-based company's collapse in late 2001.

Forney joined Enron in 1993 as a low-level generation unit manager, then moved into the company's expanding field of energy trading, where he thrived. He was assigned in 1997 to the Portland office, which handled California power trading under the state's ill-fated electricity deregulation law, and became manager of the real-time trading desk in 1999.

That desk, according to federal prosecutors, hatched the colorfully named schemes -- like "Death Star,'' "Get Shorty'' and "Ricochet'' -- that cheated consumers, fooled state overseers and generated profit increases of as much as 1,500 percent in two years.

Forney said recently that he was the author of "Death Star," which was also known within Enron as Forney's Perpetual Loop. Company traders created the appearance of congestion on the California power grid, then collected a premium price from the state for relieving congestion and delivering electricity where it was needed; in fact, that electricity was looped through transmission lines outside the state and never delivered anywhere.

"Enron purported to move electricity in directions that would relieve congestion, when in fact the electricity was scheduled to flow in a circular pattern,'' Forney said in his plea agreement. He said the California Independent System Operator, which managed the grid, was unable to detect the pattern.

Evidence of such manipulation was starkly illustrated in June when audiotapes of conversations between Enron traders in Portland were released during a legal case in Washington state.

"If the line's not congested, then I just look if I can congest it," one trader said during an August 2000 phone call. "If you can congest it, that's a moneymaker no matter what."

In another taped call, in November 2000, two Enron traders chortled about fleecing "Grandma Millie'' and "those poor grandmothers in California."

Forney's plea agreement also acknowledged a role in "Ricochet,'' in which Enron bought price-capped electricity from the California market and then resold it to California at a price above the cap.

In a quietly arranged appearance before U.S. District Judge Martin Jenkins in San Francisco, Forney pleaded guilty to a single count of conspiring to commit wire fraud, and the government agreed to drop 10 other charges contained in a grand jury indictment last December.

Prather, Forney's attorney, said the plea agreement does not specify a sentence, but Forney hopes for a recommendation of leniency based on his cooperation.

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IEA: Electricity investment surpasses oil and gas for the first time

Electricity Investment Surpasses Oil and Gas 2016, driven by renewable energy, power grids, and energy efficiency, as IEA reports lower oil and gas spending, rising solar and wind capacity, and declining coal power plant approvals.

 

Key Points

A 2016 milestone where electricity topped global energy investment, led by renewables, grids, and efficiency, per the IEA.

✅ IEA: electricity investment hit $718b; oil and gas fell to $650b.

✅ Renewables led with $297b; solar and wind unit costs declined.

✅ Coal plant approvals plunged; networks and storage spending rose.

 

Investments in electricity surpassed those in oil and gas for the first time ever in 2016 on a spending splurge on renewable energy and power grids as the fall in crude prices led to deep cuts, the International Energy Agency (IEA) said.

Total energy investment fell for the second straight year by 12 per cent to US$1.7 trillion compared with 2015, the IEA said. Oil and gas investments plunged 26 per cent to US$650 billion, down by over a quarter in 2016, and electricity generation slipped 5 per cent.

"This decline (in energy investment) is attributed to two reasons," IEA chief economist Laszlo Varro told journalists.

"The reaction of the oil and gas industry to the prolonged period of low oil prices which was a period of harsh investment cuts; and technological progress which is reducing investment costs in both renewable power and in oil and gas," he said.

Oil and gas investment is expected to rebound modestly by 3 per cent in 2017, driven by a 53 per cent upswing in U.S. shale, and spending in Russia and the Middle East, the IEA said in a report.

"The rapid ramp up of U.S. shale activities has triggered an increase of U.S. shale costs of 16 per cent in 2017 after having almost halved from 2014-16," the report said.

The global electricity sector, however, was the largest recipient of energy investment in 2016 for the first time ever, overtaking oil, gas and coal combined, the report said.

"Robust investments in renewable energy and increased spending in electricity networks, which supports the outlook that low-emissions sources will cover most demand growth, made electricity the biggest area of capital investments," Varro said.

Electricity investment worldwide was US$718 billion, lifted by higher spending in power grids which offset the fall in power generation investments.

"Investment in new renewables-based power capacity, at US$297 billion, remained the largest area of electricity spending, despite falling back by 3 per cent as clean energy investment in developing nations slipped, the report said."

Although renewables investments was 3 per cent lower than five years ago, capacity additions were 50 per cent higher and expected output from this capacity about 35 per cent higher, thanks to the fall in unit costs and technology improvements in solar PV and wind generation, the IEA said.

 

COAL INVESTMENT IS COMING TO AN END

Investments in coal-fired electricity plants fell sharply. Sanctioning of new coal power plants fell to the lowest level in nearly 15 years, reflecting concerns about local air pollution, and emergence of overcapacity and competition from renewables, with renewables poised to eclipse coal in global power generation, notably in China. Coal investments, however, grew in India.

"Coal investment is coming to an end. At the very least, it is coming to a pause," Varro said.

The IEA report said energy efficiency investments continued to expand in 2016, reaching US$231 billion, with most of it going to the building sector globally.

Electric vehicles sales rose 38 per cent in 2016 to 750,000 vehicles at $6 billion, and represented 10 per cent of all transport efficiency spending. Some US$6 billion was spent globally on electronic vehicle charging stations, the IEA said.

Spending on electricity networks and storage continued the steady rise of the past five years, as surging electricity demand puts power systems under strain, reaching an all-time high of US$277 billion in 2016, with 30 per cent of the expansion driven by China’s spending in its distribution system, the report said.

China led the world in energy investments with 21 per cent of global total share, the report said, driven by low-carbon electricity supply and networks projects.

Although oil and gas investments fell in the United States in 2016, its total energy investments rose 16 per cent, even as Americans use less electricity in recent years, on the back of spending in renewables projects, the IEA report said.

 

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Electricity users in Newfoundland have started paying for Muskrat Falls

Muskrat Falls rate mitigation offsets Newfoundland Power's rate stabilization decrease as NL Hydro begins cost recovery; Public Utilities Board approval enables collections while Labrador-Island Link nears commissioning, stabilizing electricity rates despite megaproject delays, overruns.

 

Key Points

Muskrat Falls rate mitigation is NL Hydro's cost recovery via power rates to stabilize bills as commissioning nears.

✅ Offsets 6.4% decrease with a 6.1% rate increase

✅ About 6% now funds NL Hydro's rate mitigation

✅ Collections begin as Labrador-Island Link nears commissioning

 

With their July electricity bill, Newfoundland Power customers have begun paying for Muskrat Falls, though a lump-sum credit was also announced to offset costs and bills haven't significantly increased — yet.

In a July newsletter, Newfoundland Power said electricity bills were set to decrease by 6.4 per cent as part of the annual rate stabilization adjustment, which reflects the cost of electricity generation.

Instead, that decrease has been offset by a 6.1 increase in electricity rates so Newfoundland and Labrador Hydro can begin recovering the cost of Muskrat Falls, with a $5.2-billion federal package also underpinning the project, the $13-billion hydroelectric megaproject that is billions over budget and years behind schedule.

That means for residential customers, electricity rates will decrease to 12.346 cents per kilowatt, though the basic customer charge will go up slightly from $15.81 to $15.83. According to an N.L. Hydro spokesperson, about six per cent of electricity bills will now go toward what it calls a "rate mitigation fund." 

N.L. Hydro claims victory in Muskrat Falls arbitration dispute with Astaldi
Software troubles blamed for $260M Muskrat Falls cost increase, with N.L. power rates stable for now
The spokesperson said N.L. Hydro is expecting the rate increase to result in $43 million this year, according to a recent financial update from the energy corporation — a tiny fraction of the project's cost. 

N.L. Hydro asked the Public Utilities Board to approve the rate increase, a process similar to Nova Scotia's recent 14% approval by its regulator, in May. In a letter, Energy, Industry and Technology Minister Andrew Parsons supported the increase, though he asked N.L. Hydro to keep electricity rates "as close to current levels as possible. 

Province modifies order in council
Muskrat Falls is not yet fully online — largely due to software problems with the Labrador-Island Link transmission line — and an order in council dictated that ratepayers on the island of Newfoundland would not begin paying for the project until the project was fully commissioned. 

The provincial government modified that order in council so N.L. Hydro can begin collecting costs associated with Muskrat Falls once the project is "nearing" commissioning.

In June, N.L. Hydro said the project was expected to finally be completed by the end of the year.

In an interview with CBC News, Progressive Conservative interim leader David Brazil said the decision to begin recovering the cost of Muskrat Falls from consumers should have been delayed.

"There was an opportunity here for people to get some reprieve when it came to their electricity bills and this administration chose not to do that, not to help the people while they're struggling," he said.

In a statement, Parsons said reducing the rate was not an option, and would have resulted in increased borrowing costs for Muskrat Falls.

"Reducing the rate for one year to have it increase significantly the following year is not consistent with rate mitigation and also places an increased financial burden on taxpayers one year from now," Parsons said.

Decision 'reasonable': Consumer advocate
Brazil said his party didn't know the payments from Muskrat Falls would start in July, and criticized the government for not being more transparent.

A person wearing a blue shirt and black blazer stands outside on a lawn.
N.L. consumer advocate Dennis Browne says it makes sense to begin recouping the cost of Muskrat Falls. (Garrett Barry/CBC)
Newfoundland and Labrador consumer advocate Dennis Browne said the decision to begin collecting costs from consumers was "reasonable."

"We're into a financial hole due to Muskrat Falls, and what has happened is in order to stabilize rates, we have gone into rate stabilization efforts," he said.

In February, the provincial and federal governments signed a complex agreement to shield ratepayers aimed at softening the worst of the financial impact from Muskrat Falls. Browne noted even with the agreement, the provincial government will have to pay hundreds of millions in order to stabilize electricity rates.

"Muskrat Falls would cost us $0.23 a kilowatt, and that is out of the range of affordability for most people, and that's why we're into rate mitigation," he said. "This was part of a rate mitigation effort, and I accepted it as part of that."

 

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Ontario Launches Largest Competitive Energy Procurement in Province’s History

Ontario Competitive Energy Procurement accelerates renewables, boosts grid reliability, and invites competitive bids across solar, wind, natural gas, and storage, driving innovation, lower costs, and decarbonization to meet rising electricity demand and ensure power supply.

 

Key Points

Ontario Competitive Energy Procurement is a competitive bidding program to deliver reliable, low-carbon electricity.

✅ Competitive bids from renewables, gas, and storage

✅ Targets grid reliability, affordability, and emissions

✅ Phased evaluations: technical, financial, environmental

 

Ontario has recently marked a significant milestone in its energy sector with the launch of what is being touted as the largest competitive energy procurement process in the province’s history. This ambitious initiative is set to transform the province’s energy landscape through a broader market overhaul that fosters innovation, enhances reliability, and addresses the growing demands of Ontario’s diverse population.

A New Era of Energy Procurement

The Ontario government’s move to initiate this massive competitive procurement process underscores a strategic shift towards modernizing and diversifying the province’s energy portfolio. This procurement exercise will invite bids from a broad spectrum of energy suppliers and technologies, ranging from traditional sources like natural gas to renewable energy options such as solar and wind power. The aim is to secure a reliable and cost-effective energy supply that aligns with Ontario’s long-term environmental and economic goals.

This historic procurement process represents a major leap from previous approaches by emphasizing a competitive marketplace where various energy providers can compete on an equal footing through electricity auctions and transparent bidding. By doing so, the government hopes to drive down costs, encourage technological advancements, and ensure that Ontarians benefit from a more dynamic and resilient energy system.

Key Objectives and Benefits

The primary objectives of this procurement initiative are multifaceted. First and foremost, it seeks to enhance the reliability of Ontario’s electricity grid. As the province experiences population growth and increased energy demands, maintaining a stable and dependable supply of electricity is crucial, and interprovincial imports through an electricity deal with Quebec can complement local generation. This procurement process will help identify and integrate new sources of power that can meet these demands effectively.

Another significant goal is to promote environmental sustainability. Ontario has committed to reducing its greenhouse gas emissions through Clean Electricity Regulations and transitioning to a cleaner energy mix. By inviting bids from renewable energy sources and innovative technologies, the government aims to support its climate action plan and contribute to the province’s carbon reduction targets.

Cost-effectiveness is also a central focus of the procurement process. By creating a competitive environment, the government anticipates that energy providers will strive to offer more attractive pricing structures and fair electricity cost allocation practices for ratepayers. This, in turn, could lead to lower energy costs for consumers and businesses, fostering economic growth and improving affordability.

The Competitive Landscape

The competitive energy procurement process will be structured to encourage participation from a wide range of energy providers. This includes not only established companies but also emerging players and startups with innovative technologies. By fostering a diverse pool of bidders, the government aims to ensure that all viable options are considered, ultimately leading to a more robust and adaptable energy system.

Additionally, the process will likely involve various stages of evaluation, including technical assessments, financial analyses, and environmental impact reviews. This thorough evaluation will help ensure that selected projects meet the highest standards of performance and sustainability.

Implications for Stakeholders

The implications of this procurement process extend beyond just energy providers and consumers. Local communities, businesses, and environmental organizations will all play a role in shaping the outcomes. For communities, this initiative could mean new job opportunities and economic development, particularly in regions where new energy projects are developed. For businesses, the potential for lower energy costs and access to innovative energy solutions, including demand-response initiatives like the Peak Perks program, could drive growth and competitiveness.

Environmental organizations will be keenly watching the process to ensure that it aligns with broader sustainability goals. The inclusion of renewable energy sources and advanced technologies will be a critical factor in evaluating the success of the initiative in meeting Ontario’s climate objectives.

Looking Ahead

As Ontario embarks on this unprecedented energy procurement journey, the outcomes will be closely watched by various stakeholders. The success of this initiative will depend on the quality and diversity of the bids received, the efficiency of the evaluation process, and the ability to integrate new energy sources into the existing grid, while advancing energy independence where feasible.

In conclusion, Ontario’s launch of the largest competitive energy procurement process in its history is a landmark event that holds promise for a more reliable, sustainable, and cost-effective energy future. By embracing competition and innovation, the province is setting a new standard for energy procurement that could serve as a model for other regions seeking to modernize their energy systems. The coming months will be crucial in determining how this bold initiative will shape Ontario’s energy landscape for years to come.

 

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Iran to Become Regional Hub for Renewable Energies

Iran Renewable Energy Strategy targets productivity first, then wind power expansion, investment, and exports, overcoming US sanctions, banking and forex limits, via private sector partnerships, precise wind maps, and regional grid interconnections.

 

Key Points

A policy prioritizing efficiency, wind deployment, and investor access while navigating US sanctions and currency limits.

✅ Prioritize efficiency, then scale wind generation capacity

✅ Leverage private sector, rial contracts, attract foreign capital

✅ Map high-wind corridors: Zabol, Khaf, Doroud; target exports

 

Deputy Energy Minister on Renewable Energies Affairs says the U.S. sanctions have currently affected the economic, banking and forex sectors of the country as the country‘s medicine is under sanctions and it means renewable energies are also under sanctions, and, globally, pandemic disruptions have compounded pressures on supply chains.

Speaking in a press conference yesterday, Mohammad Satkin said leading countries first focus on productivity then they turn to electricity production and the ministry in the first step has focused on productivity then on renewables, noting that renewables are now the cheapest new power in many regions, reiterating that the ministry will use all existing potentials in this regard especially in utilizing wind.

He added that the ministry is doing its best that the country would become the hub in the region for rush of investors and those who want take advantage of Iran’s experience in renewables, as markets like the U.S. scale renewables to a quarter of generation in coming years.

Satkin added that in the eastern part, the country has the biggest windy fields with capacity over 40mw. So the ministry is doing its best with full support of the private sector in equipping and investing in this field to carry out new policies.

He noted that in the past 12 years, wind potentials of the country have been under study, noting that country has three special channels in the east as one of them is north of Zabol which is very valuable in terms of energy and it has capability for construction of 2 to 3mw power station.

Satkin further said Khaf channel is the other one which has one of the most unique winds in the world, while Saudi wind expansion underscores regional momentum, and it can be developed for over 1000mw station. The windy region of Doroud is the third channel where the 50mw project has been kicked off there and it has capability for construction of some thousand-megawatt wind power station.

He added that Iran has prepared one of the most precise maps and it has even identified the border regions like with Afghanistan and perhaps in the future, Iran and Afghanistan may launch a joint project as Iran has enough expertise to offer its neighboring countries and as IRENA's decarbonisation roadmap highlights wider socio-economic benefits.

On signing agreement with foreign companies, Satkin said the ministry pays the sum of all contracts with domestic companies is paid in national currency rial as it is unable to pay in dollar or other currencies but Iranian companies may enjoy having foreign backings, including initiatives like ADFD-IRENA funding that support developing markets, and the ministry tries to attract foreign capital.

He also pointed to exports of renewables, adding that the government has authorized export of renewable energy but it needs proper planning to be assured of electricity production in order to export it to the neighboring states whenever they need, especially as Ireland targets over one-third green power within a few years.

 

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Opinion: UK Natural Gas, Rising Prices and Electricity

European Energy Market Crisis drives record natural gas and electricity prices across the EU, as LNG supply constraints, Russian pipeline dependence, marginal pricing, and renewables integration expose volatility in liberalised power markets.

 

Key Points

A 2021 surge in European gas and electricity prices from supply strains, demand rebounds, and marginal pricing exposure.

✅ Record TTF gas and day-ahead power prices across Europe

✅ LNG constraints and Russian pipeline dependence tightened supply

✅ Debate over marginal pricing vs regulated models intensifies

 

By Ronan Bolton

The year 2021 was a turbulent one for energy markets across Europe, as Europe's energy nightmare deepened across the region. Skyrocketing natural gas prices have created a sense of crisis and will lead to cost-of-living problems for many households, as wholesale costs feed through into retail prices for gas and electricity over the coming months.

This has created immediate challenges for governments, but it should also encourage us to rethink the fundamental design of our energy markets as we seek to transition to net zero, with many viewing it as a wake-up call to ditch fossil fuels across the bloc.

This energy crisis was driven by a combination of factors: the relaxation of Covid-19 lockdowns across Europe created a surge in demand, while cold weather early in the year diminished storage levels and contributed to increasing demand from Asian economies. A number of technical issues and supply-side constraints also combined to limit imports of liquefied natural gas (LNG) into the continent.

Europe’s reliance on pipeline imports from Russia has once again been called into question, as Gazprom has refused to ride to the rescue, only fulfilling its pre-existing contracts. The combination of these, and other, factors resulted in record prices – the European benchmark price (the Dutch TTF Gas Futures Contract) reached almost €180/MWh on 21 December, with average day-ahead electricity prices exceeding €300/MWh across much of the continent in the following days.

Countries which rely heavily on natural gas as a source of electricity generation have been particularly exposed, with governments quickly put under pressure to intervene in the market.

In Spain the government and large energy companies have clashed over a proposed windfall tax on power producers. In Ireland, where wind and gas meet much of the country’s surging electricity demand, the government is proposing a €100 rebate for all domestic energy consumers in early 2022; while the UK government is currently negotiating a sector-wide bailout of the energy supply sector and considering ending the gas-electricity price link to curb bills.

This follows the collapse of a number of suppliers who had based their business models on attracting customers with low prices by buying cheap on the spot market. The rising wholesale prices, combined with the retail price cap previously introduced by the Theresa May government, led to their collapse.

While individual governments have little control over prices in an increasingly globalised and interconnected natural gas market, they can exert influence over electricity prices as these markets remain largely national and strongly influenced by domestic policy and regulation. Arising from this, the intersection of gas and power markets has become a key site of contestation and comment about the role of government in mitigating the impacts on consumers of rising fuel bills, even as several EU states oppose major reforms amid the price spike.

Given that renewables are constituting an ever-greater share of production capacity, many are now questioning why gas prices play such a determining role in electricity markets.

As I outline in my forthcoming book, Making Energy Markets, a particular feature of the ‘European model’ of liberalised electricity trade since the 1990s has been a reliance on spot markets to improve the efficiency of electricity systems. The idea was that high marginal prices – often set by expensive-to-run gas peaking plants – would signal when capacity limits are reached, providing clear incentives to consumers to reduce or delay demand at these peak periods.

This, in theory, would lead to an overall more efficient system, and in the long run, if average prices exceeded the costs of entering the market, new investments would be made, thus pushing the more expensive and inefficient plants off the system.

The free-market model became established during a more stable era when domestically-sourced coal, along with gas purchased on long-term contracts from European sources (the North Sea and the Netherlands), constituted a much greater proportion of electricity generation.

While prices fluctuated, they were within a somewhat predictable range, and provided a stable benchmark for the long-term contracts underpinning investment decisions. This is no longer the case as energy markets become increasingly volatile and disrupted during the energy transition.

The idea that free price formation in a competitive market, with governments standing back, would benefit electricity consumers and lead to more efficient systems was rooted in sound economic theory, and is the basis on which other major commodity markets, such as metals and agricultural crops, have been organised for decades.

The free-market model applied to electricity had clear limitations, however, as the majority of domestic consumers have not been exposed directly to real-time price signals. While this is changing with the roll-out of smart meters in many countries, the extent to which the average consumer will be willing or able to reduce demand in a predicable way during peak periods remains uncertain.

Also, experience shows that governments often come under pressure to intervene in markets if prices rise sharply during periods of scarcity, thus undermining a basic tenet of the market model, with EU gas price cap strategies floated as one option.

Given that gas continues to play a crucial role in balancing supply and demand for electricity, the options available to governments are limited, illustrating why rolling back electricity prices is harder than it appears for policymakers. One approach would be would be to keep faith with the liberalised market model, with limited interventions to help consumers in the short term, while ultimately relying on innovations in demand side technologies and alternatives to gas as a means of balancing systems with high shares of variable renewables.

An alternative scenario may see a return to old style national pricing policies, involving a move away from marginal pricing and spot markets, even as the EU prepares to revamp its electricity market in response. In the past, in particular during the post-WWII decades, and until markets were liberalised in the 1990s, governments have taken such an approach, centrally determining prices based on the costs of delivering long term system plans. The operation of gas plants and fuel procurement would become a much more regulated activity under such a model.

Many argue that this ‘traditional model’ better suits a world in which governments have committed to long-term decarbonisation targets, and zero marginal cost sources, such as wind and solar, play a more dominant role in markets and begin to push down prices.

A crucial question for energy policy makers is how to exploit this deflationary effect of renewables and pass-on cost savings to consumers, whilst ensuring that the lights stay on.

Despite the promise of storage technologies such as grid-scale batteries and hydrogen produced from electrolysis, aside from highly polluting coal, no alternative to internationally sourced natural gas as a means of balancing electricity systems and ensuring our energy security is immediately available.

This fact, above all else, will constrain the ambitions of governments to fundamentally transform energy markets.

Ronan Bolton is Reader at the School of Social and Political Science, University of Edinburgh and Co-Director of the UK Energy Research Centre. His book Making Energy Markets: The Origins of Electricity Liberalisation in Europe is to be published by Palgrave Macmillan in 2022.

 

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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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