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Canada Net-Zero Grid Lessons highlight Europe's energy transition risks: Germany's power prices, wind and solar variability, nuclear phaseout, grid reliability, storage, market design, policy reforms, and distributed energy resources for resilient decarbonization.

Key Points

Lessons stress an all-of-the-above mix, robust market design, storage, and nuclear to ensure reliability, affordability.

✅ Diversify: nuclear, hydro, wind, solar, storage for reliability.

✅ Reform markets and grid planning for integration and flexibility.

✅ Build fast: streamline permitting, invest in transmission and DERs.

Europe is currently suffering the consequences of an uncoordinated rush to carbon-free electricity that experts warn could hit Canada as well unless urgent action is taken.

Power prices in Germany, for example, hit a record 91 euros ($135 CAD) per megawatt-hour earlier this month. That is more than triple what electricity costs in Ontario, where greening the grid could require massive investment, even during periods of peak demand.

Experts blame the price spikes in large part on a chaotic transition to a specific set of renewable electricity sources - wind and solar - at the expense of other carbon-free supplies such as nuclear power. Germany, Europe’s largest economy, plans to close its last remaining nuclear power plant next year despite warnings that renewables are not being added to the German grid quickly enough to replace that lost supply.

As Canada prepares to transition its own electricity grid to 100 per cent net-zero supplies by 2035, with provinces like Ontario planning new wind and solar procurement, experts say the European power crisis offers lessons this country must heed in order to avoid a similar fate.

'A CAUTIONARY TALE'
“Some countries have rushed their transition without thinking about what people need and when they need it,” said Chris Bentley, managing director of Ryerson University’s Legal Innovation Zone who also served as Ontario’s Minister of Energy from 2011 to 2013, in an interview. “Germany has experienced a little bit of this issue recently when the wind wasn’t blowing.”

Wind power usually provides between 20 and 30 per cent of Germany’s electricity needs, but the below-average breeze across much of continental Europe in recent months has pushed that figure down.

“There is a cautionary tale from the experience in Europe,” said Francis Bradley, chief executive officer of the Canadian Electricity Association, in an interview. “There was also a cautionary tale from what took place this past winter in Texas,” he added, referring to widespread power failures in Texas spawned by a lack of backup power supplies during an unusually cold winter that led to many deaths.

The first lesson Canada must learn from those cautionary tales, Bradley said, “is the need to pursue an all-of-the-above approach.”

“It is absolutely essential that every opportunity and every potential technology for low-carbon or no-carbon electricity needs to be pursued and needs to be pursued to the fullest,” he said.

The more important lesson for Canada, according to Binnu Jeyakumar, is about the need for a more holistic, nuanced approach to our own net-zero transition.

“It is very easy to have runaway narratives that just pinpoint the blame on one or two issues, but the lesson here isn’t really about the reliability of renewables as there are failures that occur across all sources of electricity supply,” said Jeyakumar, director of clean energy for the Pembina Institute, in an interview. 

“The takeaway for us is that we need to get better at learning how to integrate an increasingly diverse electricity grid,” she said. “It is not necessarily the technologies themselves, it is about how we do grid planning, how are our markets structured and are we adapting them to the trends that are evolving in the electricity and energy sectors.”
 

'ABSOLUTELY ENORMOUS' CHALLENGE IS 'ALMOST MIND-BENDING'
Canada already gets the vast majority of its electricity from emission-free sources. Hydro provides roughly 60 per cent of our power, nuclear contributes another 15 per cent and renewables such as wind and solar contribute roughly seven per cent more, according to federal government data.

Tempting as it might be to view the remaining 18 per cent of Canadian electricity that is supplied by oil, natural gas and coal as a small enough proportion that it should be relatively easy to replace, with some analyses warning that scrapping coal abruptly can be costly for consumers, the reality is much more difficult.

“It is the law of diminishing returns or the 80-20 rule where the first 80 per cent is easy but the last 20 per cent is hard,” Bradley explained. “We already have an electricity sector that is 80 per cent GHG-free, so getting rid of that last 20 per cent is the really difficult part because the low-hanging fruit has already been picked.”

Key to successfully decarbonizing Canada’s power grid will be the recognition that electricity demand is constantly growing, a point reinforced by a recent power challenges report that underscores the scale. That means Canada needs to build out enough emission-free power sources to replace existing fossil fuel-based supplies while also ensuring adequate supplies for future demand.

“It is one thing to say that by 2035 we are going to have a decarbonized electricity system, but the challenge really is the amount of additional electricity that we are going to need between now and 2035,” said John Gorman, chief executive officer of the Canadian Nuclear Association, which has argued that nuclear is key to climate goals in Canada, and former CEO of the Canadian Solar Industries Association, in an interview. “It is absolutely enormous, I mean, it is almost mind-bending.”

Canada will need to triple the amount of electricity produced nationwide by 2050, according to a report from SNC-Lavalin published earlier this year, and provinces such as Ontario face a shortfall over the next few years, Gorman said. Gorman said that will require adding between five and seven gigawatts of new installed capacity to Canada’s electricity grid every year from 2021 through 2050 or more than twice the amount of new power supply Canada brings online annually right now.

For perspective, consider Ontario’s Bruce Power nuclear facility. It took 27 years to bring that plant to its current 6.4 gigawatt (GW) capacity, but meeting Canada’s decarbonization goals will require adding roughly the equivalent capacity of Bruce Power every year for the next three decades.

“The task of creating enough electricity in the coming years is truly enormous and governments have not really wrapped their heads around that yet,” Gorman said. “For those of us in the energy sector, it is the type of thing that can keep you up at night.”

GOVERNMENT POLICY 'HELD HOSTAGE' BY 'DINOSAURS'
The Pembina Institute’s Jeyakumar agreed “the last mile is often the most difficult” and will require “a concerted effort both at the federal level and the provincial level.”

Governments will “need to be able to support innovation and solutions such as non-wires alternatives,” she said. “Instead of building a massive new transmission line or beefing up an old one, you could put a storage facility at the end of an existing line. Distributed energy resources provide those kinds of non-wires alternatives and they are already cost-effective and competitive with oil and gas.”

For Glen Murray, who served as Ontario’s minister of infrastructure and transportation from early 2013 to mid-2014 before assuming the environment and climate change portfolio until his resignation in mid-2017, that is a key lesson governments have yet to learn.

“We are moving away from a centralized distribution model to distributed systems where individual buildings and homes and communities will supply their own electricity needs,” said Murray, who currently works for an urban planning software company in Winnipeg, in an interview. “Yet both the federal and provincial governments are assuming that we are going to continue to have large, centralized generation of power, but that is simply not going to be the case.”

“Government policy is not focused on driving that because they are held hostage by their own hydro utilities and the big gas companies,” Murray said. “They are controlling the agenda even though they are the dinosaurs.”

Referencing the SNC-Lavalin report, Gorman noted as many as 45 small, modular nuclear reactors as well as 20 conventional nuclear power plants will be required in the coming decades, with jurisdictions like Ontario exploring new large-scale nuclear as part of that mix: “And that is in the context of also maximizing all the other emission-free electricity sources we have available as well from wind to solar to hydro and marine renewables,” Gorman said, echoing the “all-of-the-above” mindset of the Canadian Electricity Association.

There are, however, “fundamental rules of the market and the regulatory system that make it an uneven playing field for these new technologies to compete,” said Jeyakumar, agreeing with Murray’s concerns. “These are all solvable problems but we need to work on them now.”
 

'2035 IS TOMORROW'
According to Bentley, the former Ontario energy minister-turned academic, “the government's role is to match the aspiration with the means to achieve that aspiration.”

“We have spent far more time as governments talking about the goals and the high-level promises [of a net-zero electricity grid by 2035] without spending as much time as we need to in order to recognize what a massive transformation this will mean,” Bentley said. “It is easy to talk about the end-goal, but how do you get there?”

The Canadian Electricity Assocation’s Bradley agreed “there are still a lot of outstanding questions about how we are going to turn those aspirations into actual policies. The 2035 goal is going to be very difficult to achieve in the absence of seeing exactly what the policies are that are going to move us in that direction.”

“It can take a decade to go through the processes of consultations and planning and then building and getting online,” Bradley said. “Particularly when you’re talking about big electricity projects, 2035 is tomorrow.”

Jeyakumar said “we cannot afford to wait any longer” for policies to be put in place as the decisions governments make today “will then lock us in for the next 30 or 40 years into specific technologies.”

“We need to consider it like saving for retirement,” said Gorman of the Canadian Nuclear Association. “Every year that you don’t contribute to your retirement savings just pushes your retirement one more year into the future.”

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Quebec Energy Bill Tariff Delay disrupts Canada-U.S. trade, renewable energy investment, hydroelectric expansion, and clean technology projects, as Trump tariffs on aluminum and steel raise costs, threatening climate targets and green infrastructure timelines.

Key Points

A policy pause in Quebec from U.S. tariff threats, disrupting clean investment, hydro expansion, and climate targets.

✅ Tariff risk inflates aluminum and steel project costs.

✅ Quebec delays clean energy legislation amid trade uncertainty.

✅ Hydroelectric reliance complicates emissions reduction timelines.

The Trump administration's tariff threat has had a significant impact on Quebec's energy sector, with tariff threats boosting support for projects even as the uncertainty resulted in the delay of a critical energy bill. Originally introduced to streamline energy development and tackle climate change, the bill was meant to help transition Quebec towards greener alternatives while fostering economic growth. However, the U.S. threat to impose tariffs on Canadian goods, including energy products, introduced a wave of uncertainty that led to a pause in the bill's legislative process.

Quebec’s energy bill had ambitious goals of transitioning to renewable sources like wind, solar, and hydroelectric power. It sought to support investments in clean technologies and the expansion of the province's clean energy infrastructure, as the U.S. demand for Canadian green power continues to grow across the border. Moreover, it emphasized the reduction of carbon emissions, an important step towards meeting Quebec's climate targets. At its core, the bill aimed to position the province as a leader in green energy development in Canada and globally.

The interruption caused by President Donald Trump's tariff rhetoric has, however, cast a shadow over the legislation. Tariffs, if enacted, would disproportionately affect Canada's energy exports, with electricity exports at risk under growing tensions, particularly in sectors like aluminum and steel, which are integral to energy infrastructure development. These tariffs could increase the cost of energy-related projects, thereby hindering Quebec's ability to achieve its renewable energy goals and reduce carbon emissions in a timely manner.

The tariff threat was seen as a part of the broader trade tensions between the U.S. and Canada, a continuation of the trade war that had escalated under Trump’s presidency. In this context, the Quebec government was forced to reconsider its legislative priorities, with policymakers citing concerns over the potential long-term consequences on the energy industry, as leaders elsewhere threatened to cut U.S.-bound electricity to exert leverage. With the uncertainty around tariffs and trade relations, the government opted to delay the bill until the geopolitical situation stabilized.

This delay underscores the vulnerability of Quebec’s energy agenda to external pressures. While the provincial government had set its sights on an ambitious green energy future, it now faces significant challenges in ensuring that its projects remain economically viable under the cloud of potential tariffs, even as experts warn against curbing Quebec's exports during the dispute. The delay in the energy bill also reflects broader challenges faced by the Canadian energy sector, which is highly integrated with the U.S. market.

The situation is further complicated by the province's reliance on hydroelectric power, a cornerstone of its energy strategy that supplies markets like New York, where tariffs could spike New York energy prices if cross-border flows are disrupted. While hydroelectric power is a clean and renewable source of energy, there are concerns about the environmental impact of large-scale dams, and these concerns have been growing in recent years. The tariff threat may prompt a reevaluation of Quebec’s energy mix and force the government to balance its environmental goals with economic realities.

The potential imposition of tariffs also raises questions about the future of North American energy cooperation. Historically, Canada and the U.S. have enjoyed a symbiotic energy relationship, with significant energy trade flowing across the border. The energy bill in Quebec was designed with the understanding that cross-border energy trade would continue to thrive. The Trump administration's tariff threat, however, casts doubt on this stability, forcing Quebec lawmakers to reconsider how they proceed with energy policy in a more uncertain trade environment.

Looking forward, Quebec's energy sector will likely need to adjust its strategies to account for the possibility of tariffs, while still pushing for a sustainable energy future, especially if Biden outlook for Canada's energy proves more favorable for the sector in the medium term. It may also open the door for deeper discussions about diversification, both in terms of energy sources and trade partnerships, as Quebec seeks to mitigate the impact of external threats. The delay in the energy bill, though unfortunate, may serve as a wake-up call for Canadian lawmakers to rethink how they balance environmental goals with global trade realities.

Ultimately, the Trump tariff threat highlights the delicate balance between regional energy ambitions and international trade dynamics. For Quebec, the delay in the energy bill could prove to be a pivotal moment in shaping the future of its energy policy.

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Inventoried Energy Program pays ISO-NE generators for fuel security to boost winter reliability, with FERC approval, covering fossil, nuclear, hydropower, and batteries, complementing capacity markets to enhance grid resilience during severe cold snaps.

Key Points

ISO-NE program paying generators to hold fuel or energy reserves for emergencies, boosting winter reliability.

✅ FERC-approved stopgap for 2023 and 2024 winter seasons

✅ Pays for on-site fuel or stored energy during cold-trigger events

✅ Open to fossil, nuclear, hydro, batteries; limited gas participation

Electricity ratepayers in New England will pay tens of millions of dollars to fossil fuel and nuclear power plants later this decade under a program that proponents say is needed to keep the lights on during severe winters but which critics call a subsidy with little benefit to consumers or the grid, even as Connecticut is pushing a market overhaul across the region.

Last week the Federal Energy Regulatory Commission said ISO-New England, which runs the six-state power grid, can create what it calls the Inventoried Energy Program or IEP. This basically will pay certain power plants to stockpile of fuel for use in emergencies during two upcoming winters as longer-term solutions are developed.

The federal commission called it a reasonable short-term solution to avoid brownouts which doesn’t favor any given technology.

Not all agree, however, including FERC Commissioner Richard Glick, who wrote a fiery dissent to the other three commissioners.

“The program will hand out tens of millions of dollars to nuclear, coal and hydropower generators without any indication that those payments will cause the slightest change in those generators’ behavior,” Glick wrote. “Handing out money for nothing is a windfall, not a just and reasonable rate.”

The program is the latest reaction by ISO-NE to the winter of 2013-14 when New England almost saw brownouts because of a shortage of natural gas to create electricity during a pair of week-long deep freezes.

ISO-New England says the situation is more critical now because of the possible retirement of the gas-fired Mystic Generating Station in Massachusetts. As with closed nuclear plants such as Vermont Yankee and Pilgrim in Massachusetts, power plant owners say lower electricity prices, partly due to cheap renewables and partly to stagnant demand, means they can’t be profitable just by selling power.

Programs like the IEP are meant to subsidize such plants – “incentivize” is the industry term – even though some argue there is no need to subsidize nuclear in deregulated markets so they’ll stay open if they are needed.

The IEP approved last week will be applied to the winters of 2023 and 2024, after a different subsidy program expires. It sets prices, despite warnings about rushing pricing changes from industry groups, for stocking certain amounts of fuel and payments during any “trigger” event, defined as a day when the average of high and low temperatures at Bradley International Airport in Connecticut is no more than 17 degrees Fahrenheit.

These payments will be made on top of a complex system of grid auctions used to decide how much various plants get paid for generating electricity at which times.

ISO-NE estimates the new program will cost between $102 million and $148 million each winter, depending on weather and market conditions.

It says the payments are open to plants that burn oil, coal, nuclear fuel, wood chips or trash; utility-scale battery storage facilities; and hydropower dams “that store water in a pond or reservoir.” Natural gas plants can participate if they guarantee to have fuel available, but that seems less likely because of winter heating contracts.

A major complaint and groups that filed petitions opposing the project is that ISO-NE presented little supporting evidence of how prices, amount and overall cost were determined. ISO-NE argued that there wasn’t time for such analysis before the Mystic shutdown, and FERC agreed.

“The proposal is a step in the right direction … while ISO-NE finishes developing a long-term market solution,” the commission said in its ruling.

The program is the latest example of complexities facing the nation’s electricity system evolves in the face of solar and wind power, which produce electricity so cheaply that they can render traditional power uneconomic but which can’t always produce power on demand, prompting discussions of Texas grid improvements among policymakers. Another major factor is climate change, which has increased the pressure to support renewable alternatives to plants that burn fossil fuels, as well as stagnant electricity demand caused by increased efficiency.

Opponents, including many environmental groups, say electricity utilities and regulators are too quick to prop up existing systems, as the 145-mile Maine transmission line debate shows, built when electricity was sent one way from a few big plants to many customers. They argue that to combat climate change as well as limit cost, the emphasis must be on developing “non-wire alternatives” such as smart systems for controlling demand, in order to take advantage of the current system in which electricity goes two ways, such as from rooftop solar back into the grid.

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CO2 Tax for UK Offshore Energy Efficiency can accelerate adoption of aero-derivative gas turbines, flare gas recovery, and combined cycle power, reducing emissions on platforms like Equinor's Mariner and supporting net zero goals.

Key Points

A carbon price pushing operators to adopt efficient turbines, flare recovery, and combined cycle to cut emissions.

✅ Aero-derivative turbines beat industrial units on efficiency

✅ Flare gas recovery cuts routine flaring and fuel waste

✅ Combined cycle raises efficiency and lowers emissions

By Tom Baxter

The recent Energy Voice article from the Equinor chairman concerning the Mariner project heralding a ‘significant point of reference’ for growth highlighted the energy efficiency achievements associated with the platform.

I view energy efficiency as a key enabler to net zero, and alongside this the UK must start large-scale storage to meet system needs; it is a topic I have been involved with for many years.

As part of my energy efficiency work, I investigated Norwegian practices and compared them with the UK.

There were many differences, here are three;

1. Power for offshore installations is usually supplied from gas turbines burning fuel from the oil and gas processing plant, and even as the UK's offshore wind supply accelerates, installations convert that to electricity or couple the gas turbine to a machine such as a gas compressor.

There are two main generic types of gas turbine – aero-derivative and industrial. As the name implies aero-derivatives are aviation engines used in a static environment. Aero-derivative turbines are designed to be energy efficient as that is very import for the aviation industry.

Not so with industrial type gas turbines; they are typically 5-10% less efficient than a comparable aero-derivative.

Industrial machines do have some advantages – they can be cheaper, require less frequent maintenance, they have a wide fuel composition tolerance and they can be procured within a shorter time frame.

My comparison showed that aero-derivative machines prevailed in Norway because of the energy efficiency advantages – not the case in the UK where there are many more offshore industrial gas turbines.

Tom Baxter is visiting professor of chemical engineering at Strathclyde University and a retired technical director at Genesis Oil and Gas Consultants

2. Offshore gas flaring is probably the most obvious source of inefficient use of energy with consequent greenhouse gas emissions.

On UK installations gas is always flared due to the design of the oil and gas processing plant.

Though not a large quantity of gas, a continuous flow of gas is routinely sent to flare from some of the process plant.

In addition the flare requires pilot flames to be maintained burning at all times and, while Europe explores electricity storage in gas pipes, a purge of hydrocarbon gas is introduced into the pipes to prevent unsafe air ingress that could lead to an explosive mixture.

On many Norwegian installations the flare system is designed differently. Flare gas recovery systems are deployed which results in no flaring during continuous operations.

Flare gas recovery systems improve energy efficiency but they are costly and add additional operational complexity.

3. Returning to gas turbines, all UK offshore gas turbines are open cycle – gas is burned to produce energy and the very hot exhaust gases are vented to the atmosphere. Around 60 -70% of the energy is lost in the exhaust gases.

Some UK fields use this hot gas as a heat source for some of the oil and gas treatment operations hence improving energy efficiency.

There is another option for gas turbines that will significantly improve energy efficiency – combined cycle, and in parallel plans for nuclear power under the green industrial revolution aim to decarbonise supply.

Here the exhaust gases from an open cycle machine are taken to a separate turbine. This additional turbine utilises exhaust heat to produce steam with the steam used to drive a second turbine to generate supplementary electricity. It is the system used in most UK power stations, even as UK low-carbon generation stalled in 2019 across the grid.

Open cycle gas turbines are around 30 – 40% efficient whereas combined cycle turbines are typically 50 – 60%. Clearly deploying a combined cycle will result in a huge greenhouse gas saving.

I have worked on the development of many UK oil and gas fields and combined cycle has rarely been considered.

The reason being is that, despite the clear energy saving, they are too costly and complex to justify deploying offshore.

However that is not the case in Norway where combined cycle is used on Oseberg, Snorre and Eldfisk.

What makes the improved Norwegian energy efficiency practices different from the UK – the answer is clear; the Norwegian CO2 tax.

A tax that makes CO2 a significant part of offshore operating costs.

The consequence being that deploying energy efficient technology is much easier to justify in Norway when compared to the UK.

Do we need a CO2 tax in the UK to meet net zero – I am convinced we do. I am in good company. BP, Shell, ExxonMobil and Total are supporting a carbon tax.

Not without justification there has been much criticism of Labour’s recent oil tax plans, alongside proposals for state-owned electricity generation that aim to reshape the power market.

To my mind Labour’s laudable aims to tackle the Climate Emergency would be much better served by supporting a CO2 tax that complements the UK's coal-free energy record by strengthening renewable investment.

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Ontario Electricity Relief outlines an extended disconnect moratorium, potential time-of-use price changes, and Ontario Energy Board oversight to support residential customers facing COVID-19 hardship and bill payment challenges during the emergency in Ontario.

Key Points

Plan to extend disconnect moratorium and weigh time-of-use price relief for residential customers during COVID-19.

✅ Extends winter disconnect ban by 3 months

✅ Considers time-of-use price adjustments

✅ Requires Ontario Energy Board approval

The Ontario government is preparing to announce electricity relief for residential electricity users struggling because of the COVID-19 emergency, according to sources.

Sources close to those discussions say a decision has been made to lengthen the existing five-month disconnect moratorium by an additional three months.

Separately, Hydro One's relief fund has offered support to its customers during the pandemic.

News releases about the moratorium extension are currently being drafted and are expected to be released shortly, as the pandemic has reduced electricity usage across Ontario.

Electricity utilities in Ontario are currently prohibited from disconnecting residential customers for non-payment during the winter ban period from November 15 to April 30.

The province is also looking at providing further relief by adjusting time-of-use prices, such as off-peak electricity rates, which are designed to encourage shifting of energy use away from periods of high total consumption to periods of low demand.

For businesses, the province has provided stable electricity pricing to support industrial and commercial operations.

But that would require Ontario Energy Board approval and no decision has been finalized, our sources advise.

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BC Hydro Customer Crisis Fund Surplus highlights unused grants, pilot program imbalance, and calls to reduce fees or expand eligibility. Ratepayers, regulators, and social agencies urge awareness, rebates, and aid for overdue electricity bills.

Key Points

A funding carryover from BC Hydro's crisis grants, sparking debate over fee reductions or more aid eligibility.

✅ $2.9M surplus from 25-cent monthly customer fee

✅ Only 2,250 grants issued; awareness and eligibility questioned

✅ Regulator may refund balance or adjust program design

BC Hydro is sitting on a surplus of about $2.9 million in its customer crisis fund, even as BC Hydro rates rise 3% across the province, leading to calls for the utility to reduce its take from the average customer or provide more money to those in need.

B.C. Liberal Energy Critic Greg Kyllo said if the imbalance continues in the year-old pilot program, amid a provincial rate freeze announced by the province, it’s time to cut the monthly 25 cent fee in half.

"If the grant requirement or the need in the province is going to remain where it is, they should look at rolling back the contribution level in the fund," he told CTV News Vancouver from Salmon Arm.

But social agencies who were part of the consultation around the fund in the beginning said it’s more likely that people in need don’t know about the fund and more time is necessary to get the word out.

"If they collect the money, then the program’s got to change to make sure more people are able to be helped," said Gudrun Langolf of the Council of Senior Citizens Organizations of BC.

The customer crisis fund was started in spring 2018 to give people short-term relief when they can’t pay their electricity bills, especially as a $2 monthly hike pressures household budgets. Customers can apply to get a grant of up to $500 to keep the lights on, and up to $600 if electricity heats their homes.

The public utility took in about 25 cents per customer per month which added up to a revenue of $4.5 million in the year since the program started, BC Hydro confirmed to CTV News.

But the agency only gave out 2,250 grants totalling $850,000.

Administration costs added up around $750,000 – leaving the $2.9 million remaining.

The news will come as a welcome relief to those who suddenly struggle to pay their hydro bills, particularly as Alberta ratepayers are on the hook under a utility deferral program elsewhere in Canada.

Some people who come into Disability Alliance B.C. are often anxious and emotional when they’re suddenly unable to pay their bills, said Shar Saremi, an advocate there.

"I’ve had people crying. I’ve had people who have experienced a loss in the family," she said. "A lot of the time people are stressed out, anxious, really upset. They are looking for assistance, and they aren’t sure what is available for them."

She said people are only eligible if their bills are under $1,000, which could be cutting out the people who are most in need. And because the program is in its first year, it could be undersubscribed, she said.

"A lot of people don’t know about the program, don’t know how to apply, or what kind of assistance is out there," Saremi said.

The fund was established thanks to an order from the B.C. Utilities Commission, the utilities regulator in the province.

The pilot program is going to be examined by the regulator at the end of its first year.

"Any remaining balance in the account at the end of the pilot would be returned to residential ratepayers," says a BCUC fact sheet, as BC Hydro rates are set to rise 3.75% over two years. The decision on exactly what to do with the money hasn’t yet been made.

In Manitoba, a similar program is by donation, and in Newfoundland and Labrador a lump-sum credit was offered to bill payers in a separate initiative. That program raised about $200,000 from customers and $60,000 in other income. It spent $199,000 on grants to applicants, but lost about $20,000 a year.

In Ontario, private utilities are expected to raise 0.12 per cent of their revenue, and Hydro One reconnections have highlighted the stakes for nonpayment there. Across the province, those utilities gave out about $7.3 million in grants. Any unused funds in one year are rolled over to the following year.

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