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Ontario Hydro Disconnection Ban ends May 1, prompting utilities and Hydro One to push payment plans, address arrears, and link low-income assistance, as Sudbury officials urge customers to avoid spring electricity disconnections.

Key Points

A seasonal policy halting winter shutoffs in Ontario, ending May 1 as utilities emphasize payment plans and assistance.

✅ Disconnections resume after winter moratorium ends May 1.

✅ Utilities offer payment plans, arrears management, relief funds.

✅ Hydro One delays shutoffs until June 1; arrears down 60%.

The first of May has taken on new meaning this year in Ontario.

It's when the province's ban on hydro disconnections during the winter months comes to an end, even as Ontario considers extending moratoriums in some cases.

Wendy Watson, the director of communications at Greater Sudbury Utilities, says signs of the approaching deadline could be seen in their office of the past few weeks.

"We've had quite an active stream of people into our front office to catch up on their accounts and also we've had a lot of people calling us to make payment arrangements or pay their bill or deal with their arrears," she says.

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Watson says there are 590 customers in Sudbury who could face possible disconnection this spring, compared with just 60 when the ban started in November.

"They will put off until tomorrow what they can avoid today," she says.

Watson says they are hoping to work with customers to figure payment plans with more choice and flexibility and avoid the need to cut power to certain homes and businesses. 

"As we like to say we're in the distribution of energy business, not the disconnection of energy business. We want you to be able to turn the lights on," she says.

Joseph Leblanc from the Social Planning Council of Sudbury says the winter hydro disconnection ban is one of several government measures that keep low income families on the brink of disaster. (CBC)

Hydro One executive vice-president of customer care Ferio Pugilese, whose utility later extended disconnection bans across its service area, tells a different story.

He says the company has worked hard to configure payment plans for customers over the last three years amid unchanged peak-rate policies and find ways for them to pay "that fit their lifestyle."

"The threat of a disconnection is not on its own something that's going to motivate someone to pay their bills," says Pugilese.

He says Hydro One is also sending out notices this spring, but won't begin cutting anyone off until June 1st.

He says that disconnections and the amount owing from outstanding bills to Hydro One are down 60 per cent in the last year. 

Ontario Energy Minister Glenn Thibeault says there is plenty of help from government programs and utility financing options like Hydro One's relief fund for those having trouble paying their power bills. (CBC)

Sudbury MPP and Energy Minister Glenn Thibeault says his hope is that people having trouble paying their power bills will talk to their hydro utility and look at the numerous programs the government offers to help low-income citizens.

"You know, I really want every customer to have a conversation with their local utility about getting back on track and we do have those programs in place," he says.

However, Joseph Leblanc, the executive director of the Social Planning Council of Sudbury, says the winter disconnection ban is just another government policy that keeps the poor on the brink of disaster.

"It's a feel good story for the government to say that, but it's a band-aid solution. We can stop the bleeding for a little while, make sure people aren't freezing to death in Ontario," he says. 

"People choose between rent, hydro, medicine, food, and there's an option for one of those to take some pressure off for a little while."

Instead, Leblanc would like to see the government fast track the province-wide implementation of the basic income program it's testing out in a few cities. 

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Canada Clean Electricity Standard targets a net-zero grid by 2035, using carbon pricing, CO2 caps, and carbon capture while expanding renewables and interprovincial trade to decarbonize power in Alberta, Saskatchewan, and Ontario.

Key Points

A federal plan to reach a net-zero grid by 2035 using CO2 caps, carbon pricing, carbon capture, renewables, and trade.

✅ CO2 caps and rising carbon prices through 2050

✅ Carbon capture required on gas plants in high-emitting provinces

✅ Renewables build-out and interprovincial trade to balance supply

A new tool has been proposed in the federal election campaign as a way of eradicating the carbon emissions from Canada’s patchwork electricity system. 

As the country’s need for power grows through the decarbonization of transportation, industry and space heating, the Liberal Party climate plan is proposing a clean energy standard to help Canada achieve a 100% net-zero-electricity system by 2035, aligning with Canada’s net-zero by 2050 target overall. 

The proposal echoes a report released August 19 by the David Suzuki Foundation and a group of environmental NGOs that also calls for a clean electricity standard, capping power-sector emissions, and tighter carbon-pricing regulations. The report, written by Simon Fraser University climate economist Mark Jaccard and data analyst Brad Griffin, asserts that these policies would effectively decarbonize Canada’s electricity system by 2035.

“Fuel switching from dirty fossil fuels to clean electricity is an essential part of any serious pathway to transition to a net-zero energy system by 2050,” writes Tom Green, climate policy advisor to the Suzuki Foundation, in a foreword to the report. The pathway to a net-zero grid is even more important as Canada switches from fossil fuels to electric vehicles, space heating and industrial processes, even as the Canadian Gas Association warns of high transition costs.

Under Jaccard and Griffin’s proposal, a clean electricity standard would be established to regulate CO2 emissions specifically from power plants across Canada. In addition, the plan includes an increase in the carbon price imposed on electricity system releases, combined with tighter regulation to ensure that 100% of the carbon price set by the federal government is charged to electricity producers. The authors propose that the current scheduled carbon price of $170 per tonne of CO2 in 2030 should rise to at least $300 per tonne by 2050.

In Alberta, Saskatchewan, Ontario, New Brunswick and Nova Scotia, the 2030 standard would mean that all fossil-fuel-powered electricity plants would require carbon capture in order to comply with the standard. The provinces would be given until 2035 to drop to zero grams CO2 per kilowatt hour, matching the 2030 standard for low-carbon provinces (Quebec, British Columbia, Manitoba, Newfoundland and Labrador and Prince Edward Island). 

Alberta and Saskatchewan targeted 
Canada has a relatively clean electricity system, as shown by nationwide progress in electricity, with about 80% of the country’s power generated from low- or zero-emission sources. So the biggest impacts of the proposal will be felt in the higher-carbon provinces of Alberta and Saskatchewan. Alberta has a plan to switch from coal-based electric power to natural gas generation by 2023. But Saskatchewan is still working on its plan. Under the Jaccard-Griffin proposal, these provinces would need to install carbon capture on their gas-fired plants by 2030 and carbon-negative technology (biomass with carbon capture, for instance) by 2035. Saskatchewan has been operating carbon capture and storage technology at its Boundary Dam power station since 2014, but large-scale rollout at power plants has not yet been achieved in Canada. 

With its heavy reliance on nuclear and hydro generation, Ontario’s electricity supply is already low carbon. Natural gas now accounts for about 7% of the province’s grid, but the clean electricity standard could pose a big challenge for the province as it ramps up natural-gas-generated power to replace electricity from its aging Pickering station, scheduled to go out of service in 2025, even as a fully renewable grid by 2030 remains a debated goal. Pickering currently supplies about 14% of Ontario’s power. 

Ontario doesn’t have large geological basins for underground CO2 storage, as Alberta and Saskatchewan do, so the report says Ontario will have to build up its solar and wind generation significantly as part of Canada’s renewable energy race, or find a solution to capture CO2 from its gas plants. The Ontario Clean Air Alliance has kicked off a campaign to encourage the Ontario government to phase out gas-fired generation by purchasing power from Quebec or installing new solar or wind power.

As the report points out, the federal government has Supreme Court–sanctioned authority to impose carbon regulations, such as a clean electricity standard, and carbon pricing on the provinces, with significant policy implications for electricity grids nationwide.

The federal government can also mandate a national approach to CO2 reduction regardless of fuel source, encouraging higher-carbon provinces to work with their lower-carbon neighbours. The Atlantic provinces would be encouraged to buy power from hydro-heavy Newfoundland, for example, while Ontario would be encouraged to buy power from Quebec, Saskatchewan from Manitoba, and Alberta from British Columbia.

The Canadian Electricity Association, the umbrella organization for Canada’s power sector, did not respond to a request for comment on the Jaccard-Griffin report or the Liberal net-zero grid proposal.

Just how much more clean power will Canada need? 
The proposal has also kicked off a debate, and an IEA report underscores rising demand, about exactly how much additional electricity Canada will need in coming decades.

In his 2015 report, Pathways to Deep Decarbonization in Canada, energy and climate analyst Chris Bataille estimated that to achieve Canada’s climate net-zero target by 2050 the country will need to double its electricity use by that year.

Jaccard and Griffin agree with this estimate, saying that Canada will need more than 1,200 terawatt hours of electricity per year in 2050, up from about 640 terawatt hours currently.

But energy and climate consultant Ralph Torrie (also director of research at Corporate Knights) disputes this analysis.

He says large-scale programs to make the economy more energy efficient could substantially reduce electricity demand. A major program to install heat pumps and replace inefficient electric heating in homes and businesses could save 50 terawatt hours of consumption on its own, according to a recent report from Torrie and colleague Brendan Haley. 

Put in context, 50 terawatt hours would require generation from 7,500 large wind turbines. Applied to electric vehicle charging, 50 terawatt hours could power 10 million electric vehicles.

While Torrie doesn’t dispute the need to bring the power system to net-zero, he also doesn’t believe the “arm-waving argument that the demand for electricity is necessarily going to double because of the electrification associated with decarbonization.” 

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Hydro One Avista takeover rejection signals Washington regulators blocking a utility acquisition over governance risk, EPS dilution, and balance sheet impact, as investors applaud share price gains and a potential US$103M break fee.

Key Points

A regulator-led block of Hydro One's Avista bid, citing EPS dilution, balance sheet risk, and governance concerns.

✅ Washington denies approval; Idaho, Oregon decisions pending.

✅ EPS dilution avoided; balance sheet strength preserved.

✅ Shares rise 5.7%; US$103M break fee if deal collapses.

Opposition politicians may not like it but investors are applauding the rejection of Hydro One Ltd.'s $6.7-billion Avista takeover of U.S.-based utility Avista Corp.

Shares in the power company controlled by the Ontario government, which has also proposed a bill redesign to simplify statements, closed at $21.53, up $1.16 or 5.7 per cent, on the Toronto Stock Exchange on Thursday.

On Wednesday, Washington State regulators said they would not allow Ontario's largest utility to buy Avista over concerns about political risk that the provincial government, which owns 47 per cent of Hydro One's shares, might meddle in Avista's operations.

Financial analysts had predicted investors would welcome the news because the deal, announced in July 2017, would have eroded earnings per share and weakened Hydro One's balance sheet.

"The Washington regulator's denial of Avista is a positive development for the shares, in our opinion," said analyst Ben Pham of BMO Capital Markets in a report on Wednesday.

"While this may sound odd, we note that the Avista deal is expected to be EPS dilutive and result in a weaker balance sheet for (Hydro One). Not acquiring Avista and refocusing its attention on its core Ontario franchise ... along with related interprovincial arrangements such as the Ontario-Quebec electricity deal under discussion would likely be viewed positively if the deal ultimately breaks."

Decisions are yet to come from Idaho and Oregon state regulators, but Washington was probably the most important as the state contains customers making up about 60 per cent of Avista's rate base, Pham said.

He pointed out that a US$103-million break fee is to be paid to Avista if the deal collapses due to a failure to obtain regulatory approval.

CIBC analyst Robert Catellier raised his 12-month Hydro One target price by 25 cents and said many shareholders will feel "relieved" that the deal had failed.

He warned that the company's earnings power could deteriorate as the province seeks to reduce power bills by 12 per cent, despite an Ontario-Quebec hydro deal that may not lower costs.

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Ottawa Hydro Substation Heritage Designation highlights Hydro Ottawa's 1920s architecture, Art Deco facades, and municipal utility history, protecting key voltage-reduction sites in Glebe, Carling-Merivale, Holland, King Edward, and Old Ottawa South.

Key Points

A city plan to protect Hydro Ottawa's 1920s substations for architecture, utility role, and civic electrical heritage.

✅ Protects five operating voltage-reduction sites citywide

✅ Recognizes Art Deco and early 20th century utility architecture

✅ Allows emergency demolition to ensure grid safety

The city of Ottawa is looking to designate five hydro substations built nearly a century ago as heritage structures, a move intended to protect the architectural history of Ottawa's earliest forays into the electricity business, even as Ottawa electricity consumption has shifted in recent years.

All five buildings are still used by Hydro Ottawa to reduce the voltage coming from transmission lines before the electricity is transmitted to homes and businesses, and when severe weather causes outages, Sudbury Hydro crews work to reconnect service across communities.

Electricity came to Ottawa in 1882 when two carbon lamps were installed on LeBreton Flats, heritage planner Anne Fitzpatrick told the city's built heritage subcommittee on Tuesday. It became a lucrative business, and soon a privately owned monopoly that drew public scrutiny similar to debates over retroactive charges in neighboring jurisdictions.

In 1905, city council held a special meeting to buy the electrical company, which led to a dramatic drop in electricity rates for residents, a contrast with recent discussions about peak hydro rates for self-isolating customers.

The substations are now owned by Hydro Ottawa, which agreed to the heritage designations on the condition it not be prevented from emergency demolitions if it needs to address incidents such as damaging storms in Ontario while it works to "preserve public safety and the continuity of critical hydro electrical services."

Built in 1922, the substation at the intersection of Glebe and Bronson avenues was the first to be built by the new municipal electrical department, long before modern battery storage projects became commonplace on Ontario's grid.

The largest of the substations being protected dates back to 1929 and is found at the corner of Carling Avenue and Merivale Road. It was built to accommodate a growing population in areas west of downtown including Hintonburg and Mechanicsville.

The substation on Holland Avenue near the Queensway is different from the others because it was built in 1924 to serve the Ottawa Electric Railway Company. The streetcar company operated from 1891 to 1959, and urban electrical infrastructure can face failures such as the Hydro-Québec manhole fire that left thousands without power.

This substation on King Edward Avenue was built in 1931 and designed by architect William Beattie, who also designed York Street Public School in Lowertown and the substation on Carling Avenue. 

The last substation to be built in a 'bold and decorative style' is at 39 Riverdale Ave. in Old Ottawa South, according to city staff. It was designed in an Art Deco style by prominent architect J. Albert Ewart, who was also behind the Civic Hospital and nearby Southminster Church on Bank Street.

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Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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Quinone-mediated fuel cell uses a bio-inspired organic shuttle to carry electrons and protons to a nearby cobalt catalyst, improving hydrogen conversion, cutting platinum dependence, and raising efficiency while lowering costs for clean electricity.

Key Points

An affordable, bio-inspired fuel cell using an organic quinone shuttle and cobalt catalyst to move electrons efficiently

✅ Organic quinone shuttles electrons to a separate cobalt catalyst

✅ Reduces platinum use, lowering cost of hydrogen power

✅ Bio-inspired design aims to boost efficiency and durability

Fuel cells have long been viewed as a promising power source. But most fuel cells are too expensive, inefficient, or both. In a new approach, inspired by biology, a team has designed a fuel cell using cheaper materials and an organic compound that shuttles electrons and protons.

Fuel cells have long been viewed as a promising power source. These devices, invented in the 1830s, generate electricity directly from chemicals, such as hydrogen and oxygen, and produce only water vapor as emissions. But most fuel cells are too expensive, inefficient, or both.

In a new approach, inspired by biology and published today (Oct. 3, 2018) in the journal Joule, a University of Wisconsin-Madison team has designed a fuel cell using cheaper materials and an organic compound that shuttles electrons and protons.

In a traditional fuel cell, the electrons and protons from hydrogen are transported from one electrode to another, where they combine with oxygen to produce water. This process converts chemical energy into electricity. To generate a meaningful amount of charge in a short enough amount of time, a catalyst is needed to accelerate the reactions.

Right now, the best catalyst on the market is platinum -- but it comes with a high price tag, and while advances like low-cost heat-to-electric materials show promise, they address different conversion pathways. This makes fuel cells expensive and is one reason why there are only a few thousand vehicles running on hydrogen fuel currently on U.S. roads.

Shannon Stahl, the UW-Madison professor of chemistry who led the study in collaboration with Thatcher Root, a professor of chemical and biological engineering, says less expensive metals can be used as catalysts in current fuel cells, but only if used in large quantities. "The problem is, when you attach too much of a catalyst to an electrode, the material becomes less effective," he says, "leading to a loss of energy efficiency."

The team's solution was to pack a lower-cost metal, cobalt, into a reactor nearby, where the larger quantity of material doesn't interfere with its performance. The team then devised a strategy to shuttle electrons and protons back and forth from this reactor to the fuel cell.

The right vehicle for this transport proved to be an organic compound, called a quinone, that can carry two electrons and protons at a time. In the team's design, a quinone picks up these particles at the fuel cell electrode, transports them to the nearby reactor filled with an inexpensive cobalt catalyst, and then returns to the fuel cell to pick up more "passengers."

Many quinones degrade into a tar-like substance after only a few round trips. Stahl's lab, however, designed an ultra-stable quinone derivative. By modifying its structure, the team drastically slowed down the deterioration of the quinone. In fact, the compounds they assembled last up to 5,000 hours -- a more than 100-fold increase in lifetime compared to previous quinone structures.

"While it isn't the final solution, our concept introduces a new approach to address the problems in this field," says Stahl. He notes that the energy output of his new design produces about 20 percent of what is possible in hydrogen fuel cells currently on the market. On the other hand, the system is about 100 times more effective than biofuel cells that use related organic shuttles.

The next step for Stahl and his team is to bump up the performance of the quinone mediators, allowing them to shuttle electrons more effectively and produce more power. This advance would allow their design to match the performance of conventional fuel cells, but with a lower price tag.

"The ultimate goal for this project is to give industry carbon-free options for creating electricity, including thermoelectric materials that harvest waste heat," says Colin Anson, a postdoctoral researcher in the Stahl lab and publication co-author. "The objective is to find out what industry needs and create a fuel cell that fills that hole."

This step in the development of a cheaper alternative could eventually be a boon for companies like Amazon and Home Depot that already use hydrogen fuel cells to drive forklifts in their warehouses.

"In spite of major obstacles, the hydrogen economy, with efforts such as storing electricity in pipelines in Europe, seems to be growing," adds Stahl, "one step at a time."

Financial support for this project was provided by the Center for Molecular Electrocatalysis, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, and by the Wisconsin Alumni Research Foundation (WARF) through the WARF Accelerator Program.

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