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Ontario Energy Storage Procurement accelerates grid flexibility as IESO seeks lithium batteries, pumped storage, compressed air, and flywheels to balance renewables, support EV charging, and complement gas peakers during Pickering refits and rising electricity demand.

Key Points

Ontario's plan to procure 2,500 MW of storage to firm renewables, aid EV charging, and add flexible grid capacity.

✅ 2,500 MW storage plus 1,500 MW gas for 2025-2027 reliability

✅ Mix: lithium batteries, pumped storage, compressed air, flywheels

✅ Enables VPPs via EVs, demand response, and hybrid solar-storage

Ontario is staring down an electricity supply crunch and amid a rush to secure more power, it is plunging into the world of energy storage — a relatively unknown solution for the grid that experts say could also change energy use at home.

Beyond the sprawling nuclear plants and waterfalls that generate most of the province’s electricity sit the batteries, the underground caverns storing compressed air to generate electricity, and the spinning flywheels waiting to store energy at times of low demand and inject it back into the system when needed.

The province’s energy needs are quickly rising, with the proliferation of electric vehicles and growing Canada-U.S. collaboration on EV adoption, and increasing manufacturing demand for electricity on the horizon just as a large nuclear plant that supplies 14 per cent of Ontario’s electricity is set to be retired and other units are being refurbished.

The government is seeking to extend the life of the Pickering Nuclear Generating Station, planning an import agreement for power with Quebec, rolling out conservation programs, and — controversially — relying on more natural gas to fill the looming gap between demand and supply, amid Northern Ontario sustainability debates.

Officials with the Independent Electricity System Operator say a key advantage of natural gas generation is that it can quickly ramp up and down to meet changes in demand. Energy storage can provide that same flexibility, those in the industry say.

Energy Minister Todd Smith has directed the IESO to secure 1,500 megawatts of new natural gas capacity between 2025 and 2027, along with 2,500 megawatts of clean technology such as energy storage that can be deployed quickly, which together would be enough to power the city of Toronto.

It’s a far cry from the 54 megawatts of energy storage in use in Ontario’s grid right now.

Smith said in an interview that it’s the largest active procurement for energy storage in North America.

“The one thing that we want to ensure that we do is continue to add clean generation as much as possible, and affordable and clean generation that’s reliable,” he said.

Rupp Carriveau, director of the Environmental Energy Institute at the University of Windsor, said the timing is good.

“The space is there, the technology is there, and the willingness among private industry to respond is all there,” he said. “I know of a lot of companies that have been rubbing their hands together, looking at this potential to construct storage capacity.”

Justin Rangooni, the executive director of Energy Storage Canada, said because of the relatively tight timelines, the 2,500 megawatts is likely to be mostly lithium batteries. But there are many other ways to store energy, other than a simple battery.

“As we get to future procurements and as years pass, you’ll start to see possibly pump storage, compressed air, thermal storage, different battery chemistry,” he said.

Pump storage involves using electricity during off-peak periods to pump water into a reservoir and slowly releasing it to run a turbine and generate electricity when it’s needed. Compressed air works similarly, and old salt caverns in Goderich, Ont., are being used to store the compressed air.

In thermal storage, electricity is used to heat water when demand is low and when it’s needed, water stored in tanks can be used as heat or hot water.

Flywheels are large spinning tops that can store kinetic energy, which can be used to power a turbine and produce electricity. A flywheel facility in Minto, Ont., also installed solar panels on its roof and became the first solar storage hybrid facility in Ontario, said a top IESO official.

Katherine Sparkes, the IESO’s director of innovation, research and development, said it’s exciting, from a grid perspective.

“As we kind of look to the future and we think about gas phase out and electrification, one of the big challenges that all power systems across North America and around the world are looking at is: how do you accommodate increasing amounts of variable, renewable resources and just make better use of your grid assets,” she said.

“Hybrids, storage generation pairings, gives you that opportunity to deal with the variability of renewables, so to store electricity when the sun isn’t shining, or the wind isn’t blowing, and use it when you need it to.”

The small amount of storage already in the system provides more fine tuning of the electricity system, whereas 2,500 megawatts will be a more “foundational” part of the toolkit, said Sparkes.

But what’s currently on the grid is far from the only storage in the province. Many commercial and industrial consumers, such as large manufacturing facilities or downtown office buildings, are using storage to manage their electricity usage, relying on battery energy when prices are high.

The IESO sees that as an opportunity and has changed market rules to allow those customers to sell electricity back to the grid when needed.

As well, the IESO has its eye on the thousands of mobile batteries in electric vehicles, a trend seen in California, that shuttle people around the province every day but sit unused for much of the time.

“If we can enable those batteries to work together in aggregation, or work with other types of technologies like solar or smart building systems in a configuration, like a group of technologies, that becomes a virtual power plant,” Sparkes said.

Peak Power, a company that seeks to “make power plants obsolete,” is running a pilot project with electric vehicles in three downtown Toronto office buildings in which the car batteries can provide electricity to reduce the facility’s overall demand during peak periods using vehicle-to-building charging with bidirectional chargers.

In that model, one vehicle can earn $8,000 per year, said cofounder and chief operating officer Matthew Sachs.

“Battery energy storage will change the energy industry in the same way and for the same reasons that refrigeration changed the milk industry,” he said.

“As you had refrigeration, you could store your commodity and that changed the distribution channels of it. So I believe that energy storage is going to radically change the distribution channels of energy.”

If every home has a solar panel, an electric vehicle and a residential battery, it becomes a generating station, a decentralization that’s not only more environmentally friendly, but also relies less on “monopolized utilities,” Sachs said.

In the next decade, energy demand from electric vehicles is projected to skyrocket, making vehicle-to-grid integration increasingly relevant, and Sachs said the grid can’t grow enough to accommodate a peak demand of hundreds of thousands of vehicles being plugged in to charge at the end of the workday commute. Authorities need to be looking at more incentives such as time-of-use pricing and price signals to ensure the demand is evened out, he said.

“It’s a big risk as much as it’s a big opportunity,” he said. “If we do it wrong, it will cost us billions to fix. If we do it right, it can save us billions.”

Jack Gibbons, the chair of the Ontario Clean Air Alliance, said the provincial and federal governments need to fund and install bidirectional chargers in order to fully take advantage of electric vehicles.

“This is a huge missed opportunity,” he said.

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Eskom Wind Power Curtailment reflects South Africa's lockdown-driven drop in electricity demand, prompting grid-balancing measures as Eskom signals reduced IPP procurement from renewable energy projects during low-demand hours, despite guarantees and flexible generation constraints.

Key Points

A temporary reduction of wind IPP purchases by Eskom to balance surplus grid capacity during the COVID-19 lockdown slump

✅ Demand drop of 7,500 MW reduced need for variable renewables.

✅ Curtailment likely during low-demand early-morning hours.

✅ IPP revenues protected via contract extensions and guarantees.

South African state utility Eskom has told independent wind farms that it could buy less of their power in the coming days, as electricity demand has plummeted during a lockdown, reflecting the Covid-19 impact on renewables worldwide, aimed at curbing the spread of the coronavirus.

Eskom, which is mired in a financial crisis and has struggled to keep the lights on in the past year, said on Tuesday that power demand had dropped by more than 7,500 megawatts since the lockdown started on Friday and that it had taken offline some of its own generators.

The utility supplements its generating capacity, which is mainly derived from coal, by buying power from solar and wind farms, as wind becomes a competitive source of electricity globally, under contracts signed as part of the government’s renewable energy programme.

Spokesman Sikonathi Mantshantsha said Eskom had not yet curtailed power procurement from wind farms but that it had told them, echoing industry warnings on wind investment risk seen by the sector, this could happen “for a few hours a day during the next few days, perhaps until the lockdown is lifted”.

“Most of them are able to feed power into the grid in the early hours of the day. That coincides with the lowest demand period and can highlight curtailment challenges when supply exceeds need. And we now have a lot more capacity than needed,” Mantshantsha said.

During the lockdown imposed by President Cyril Ramaphosa, businesses apart from those deemed “essential services” are closed, mirroring Spanish wind factory closures elsewhere. Many power-hungry mines and furnaces have suspended operations.

Eskom has relatively little of its own “flexible generation” capacity, which can be ramped up or down easily, unlike regions riding a renewables boom in South Australia to export power.

The government has committed to buy up to 200 billion rand ($11.1 billion) of electricity from independent power producers and has issued state guarantees for those purchases.

“They will be compensated for their losses, amid U.S. utility-solar slowdowns being reported - each day lost will be added to their contracts,” Mantshantsha said of the wind farms. “In the end they will not be worse off.”

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V.C. Summer nuclear plant leak update: Dominion Energy repaired a valve in the reactor cooling system; radioactive water stayed within containment, NRC oversight continues as power output ramps toward full operation.

Key Points

A minor valve leak in the reactor cooling system contained onsite; Dominion repaired it as the plant resumes power.

✅ Valve leak in piping to steam generators, not environmental release.

✅ Radioactive water remained in containment, monitored per NRC rules.

✅ Plant ramping from 17% power; full operations may take days.

The V.C. Summer nuclear power plant, which has been shut down since early November because of a pipe leak, is expected to begin producing energy in a few days, a milestone comparable to a new U.S. reactor startup reported recently.

Dominion Energy says it has fixed the small leak in a pipe valve that allowed radioactive water to drip out. The company declined to say when the plant would be fully operational, but spokesman Ken Holt said that can take several days, amid broader discussions about the stakes of early nuclear closures across the industry.

The plant was at 17 percent power Wednesday, he said, as several global nuclear project milestones continue to be reported this year.

Holt, who said Dominion is still investigating the cause, said water that leaked was part of the reactor cooling system. While the water came in contact with nuclear fuel in the reactor, the water never escaped the plant's containment building and into the environment, Holt said.

He characterized the valve leak as '"uncommon" but not unexpected. The nuclear leak occurred in piping that links the nuclear reactor with the power plant's steam generators. Hundreds of pipes are in that part of the nuclear plant, a complexity often cited in the energy debate over struggling nuclear plants nationwide.

"There is always some level of leakage when you are operating, but it is contained and monitored, and when it rises to a certain level, you may take action to stop it," Holt said.

A nuclear safety watchdog has criticized Dominion for not issuing a public notice about the leak, but both the company and the U.S. Nuclear Regulatory Commission say the amount was so small it did not require notice.

The V.C. Summer Nuclear plant is about 25 miles northwest of Columbia in Fairfield County. It was licensed in the early 1980s. At one point, Dominion's predecessor, SCE&G, partnered with state owned Santee Cooper to build two more reactors there, even as new reactors in Georgia were taking shape. But the companies walked away from the project in 2017, citing high costs and troubles with its chief contractor, Westinghouse, even as closures such as Three Mile Island's shutdown continued to influence policy.

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Ontario Comprehensive Electricity Plan delivers Global Adjustment reductions for industrial and commercial non-RPP customers, lowering electricity rates, shifting renewable energy costs, and enhancing competitiveness across Ontario businesses in 2022, with additional 4 percent savings.

Key Points

Ontario's plan lowers Global Adjustment by shifting renewable costs, cutting industrial and commercial bills 15-17%.

✅ Shifts above-market non-hydro renewable costs to the Province

✅ Reduces GA for industrial and commercial non-RPP customers

✅ Additional 4% savings on 2022 bills after GA deferral

As of January 1, 2022, industrial and commercial electricity customers will benefit from the full savings introduced through the Ontario government’s Comprehensive Electricity Plan, which supports stable electricity pricing for industrial and commercial companies, announced in Budget 2020, and first implemented in January 2021. This year customers could see an additional four percent savings compared to their bills last year, bringing the full savings from the Comprehensive Electricity Plan to between 15 and 17 per cent, making Ontario a more competitive place to do business.

“Our Comprehensive Electricity Plan has helped reverse the trend of skyrocketing electricity prices that drove jobs out of Ontario,” said Todd Smith, Minister of Energy. “Over 50,000 customers are benefiting from our government’s plan which has reduced electricity rates on clean and reliable power, allowing them to focus on reinvesting in their operations and creating jobs here at home.”

Starting on January 1, 2021, the Comprehensive Electricity Plan reduced overall Global Adjustment (GA) costs for industrial and commercial customers who do not participate in the Regulated Price Plan (RPP) by shifting the forecast above-market costs of non-hydro renewable energy, such as wind, solar and bioenergy, from the rate base to the Province, alongside energy-efficiency programs that complement demand reduction efforts.

“Since taking office, our government has listened to job creators and worked to lower the costs of doing business in the province. Through these significant reductions in electricity prices through the Comprehensive Electricity Plan, customers all across Ontario will benefit from significant savings in their business operations in 2022,” said Vic Fedeli, Minister of Economic Development, Job Creation and Trade. “By continuing to reduce electricity costs, lowering taxes, and cutting red tape our government has reduced the cost of doing business in Ontario by nearly $7 billion annually to ensure that we remain competitive, innovative and poised for economic recovery.”

As part of its COVID response, including electricity relief for families and small businesses, Ontario had deferred a portion of GA between April and June 2020 for industrial and non-RPP commercial customers, with more than 50,000 customers benefiting. Those same businesses paid back these deferred GA costs over 12 months, between January 2021 and December 2021, while the province prepared to extend disconnect moratoriums for residential customers.

During the pandemic, residential electricity use rose even as overall consumption dropped, underscoring shifts in load patterns.

Now that the GA deferral repayment period is over, industrial and non-RPP commercial customers will benefit from the full cost reductions provided to them by the Comprehensive Electricity Plan, alongside temporary off-peak rate relief that supported families and small businesses. This means that, beginning January 1, 2022, these businesses could see an additional four per cent savings on their bills compared to 2021, as new ultra-low overnight pricing options emerge depending on their location and consumption.

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Washington County solar farm incentives aim to steer projects to industrial sites with tax breaks, underground grid connections, decommissioning bonds, and wildlife corridors, balancing zoning, historic preservation, and Maryland renewable energy mandates.

Key Points

Policies steer solar to industrial sites with tax breaks, buried lines, and bonds, aligning with zoning and state goals.

✅ Tax breaks to favor rooftops and parking canopies

✅ Bury new grid lines to shift projects to industrial parks

✅ Require decommissioning bonds and wildlife corridors

Incentives for establishing solar farms at industrial spaces instead of on prime farmland are among the ideas the Washington County Planning Commission is recommending for the county to update its policies regarding solar farms.

Potential incentives would include tax breaks on solar equipment and requiring developers to put power-grid connections and line extensions underground, a move tied to grid upgrade cost debates in other regions, Planning Commission members said during a Monday meeting.

The tax break could make it more attractive for a developer to put a solar farm on a roof or over a parking lot, similar to California's building-solar requirement policies that favor rooftop generation, which could cost more than putting it on farmland, said Commission member Dave Kline, who works for FirstEnergy.

Requiring a company to bury new transmission lines could steer them to industrial or business parks where, theoretically, transmission lines are more readily available, Kline said Wednesday in a phone interview.

Chairman Clint Wiley suggested talking to industrial property owners to create a list of industrial sites that make sense for a solar site, which could generate extra income for the property owner.

Commission members also talked about requiring a wildlife corridor. Anne Arundel County requires such a corridor if a solar site is over 15 acres, according to Jill Baker, deputy director of planning and zoning. The solar site is broken into sections so animals such as deer can get through, she said.

However, that means the solar farm would take up more agricultural land, Commission member Jeremiah Weddle said. Weddle, a farmer, has repeatedly voiced concerns about solar farms using prime farmland.

County zoning law already states solar farms are prohibited in Rural Legacy Areas, Priority Preservation Areas, and within Antietam Overlay zones that preserve the Antietam National Battlefield viewshed. They also cannot be built on land with permanent preservation easements, Baker said.

However, a big reason county officials are looking to strengthen county policies for solar generating systems, or solar farms, is a recent court decision that ruled the Maryland Public Service Commission can preempt county zoning law when it comes to large solar farms.

County zoning law defines a solar energy generating system as a solar facility, with multiple solar arrays, tied into the power grid and whose primary purpose is to generate power to distribute and/or sell into the public utility grid rather than consuming that power on site.

The Maryland Court of Appeals ruled in July that the Public Service Commission can preempt local zoning regarding solar farms larger than 2 megawatts. But the ruling also stated local government is a "significant participant in the process" and the state commission must give "due consideration" to local zoning laws.

County officials are looking at recommendations for solar farms, whether they are over 2 megawatts or not.

Solar farms are a popular issue statewide, especially with Maryland solar subscriptions expanding, and were discussed at a recent Maryland Association of Counties meeting for planners, Planning and Zoning Director Stephen Goodrich said.

The thinking is the best way for counties to express their opinions about a solar project is to participate in the state commission's local public hearings, where issues like how solar owners are paid often arise, Goodrich said. Another popular idea is for the county to continue to follow its process, which requires a public hearing for a special exception to establish a solar farm. That will help the county form an opinion, on individual cases, to offer the state commission, he said.

Recommendations discussed by the Planning Commission include:

A break on personal property taxes, which is on equipment, including affordable battery storage that can firm output, to steer developers away from areas where the county doesn't want solar farms. The Board of County Commissioners have been split on tax-break agreements for solar farms, with a majority recently granting a few.

Protecting valuable historic sites.

Requiring a decommissioning bond for removing the equipment at the end of the solar farm's life. The bond is protection in case the company goes bankrupt. The county commissioners have been making such a bond a requirement when granting recent tax breaks.

Looking at allowing solar farms in stormwater-management areas.

Other counties, particularly in Western Maryland and on the Eastern Shore, are having issues with solar farms even as research to improve solar and wind advances, because land is cheaper and there are wide-open spaces, Goodrich said.

Many solar projects are being developed or proposed because state lawmakers passed legislation requiring 50% of electricity produced in the state to come from renewable sources by 2030, and a federal plan to expand solar is also shaping expectations. Of that 50%, 14.5% is to come from solar energy.

In Maryland, the average number of homes that can be powered by 1 megawatt of solar energy is about 110, according to the Solar Energy Industries Association's website.

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Site C Dam Court Ruling could halt hydroelectric project near Fort St. John, as First Nations cite Treaty 8 rights in B.C. Supreme Court against BC Hydro, reservoir flooding, and Peace River Valley impacts.

Key Points

Potential B.C. Supreme Court stop to Site C, grounded in Treaty 8 rights claims by First Nations against BC Hydro.

✅ Trial expected in 2022 before planned 2023 reservoir flooding

✅ Treaty 8 rights and Peace River Valley impacts at issue

✅ Talks ongoing among B.C., BC Hydro, West Moberly, Prophet River

The Site C dam could still be stopped by an "eleventh hour" court ruling, according to the lawyer representing B.C. First Nations opposed to the massive hydroelectric project near Fort St. John.

The B.C. government, BC Hydro and West Moberly and Prophet River First Nations were in B.C. Supreme Court Feb. 28 to set a 120-day trial, expected to begin in March 2022.

That date means a ruling would come prior to the scheduled flooding of the dam's reservoir area in 2023 said Tim Thielmann, legal counsel for the West Moberly First Nation.

"The court has left itself the opportunity for an eleventh hour cancellation of the project," he said.

Construction continues

At the core of the case is First Nations arguments the multi-billion dollar BC Hydro dam will cause irreparable harm to its territory and way of life — even as drought strains hydro production elsewhere — rights protected under Treaty 8.

The West Moberly have previously warned it believes Site C constitutes a $1 billion treaty violation.

​In 2018, the First Nations lost a bid for an injunction order, meaning construction of the dam is continuing despite warnings that delays could cost $600 million to the project.

First Nations 'deeply frustrated' after B.C. Supreme Court dismisses Site C injunction

The judge in the case said the ruling was made because if the First Nations lost the challenge, the project would be needlessly put into disarray.

Province, Nations enter talks to avoid litigation

Also this week the B.C. government announced it has entered into talks with BC Hydro and the two First Nations in an attempt to avoid the court process altogether, amid broader energy debates such as bridging the Alberta-B.C. electricity gap for climate goals.

Thielmann said the details of the talk are confidential, but his clients are willing to pursue all avenues in order to stop the dam from moving forward.

"They are trying to save what little is left [of the Peace River Valley]", he said.

Tim Thielmann of Sage Legal is representing the West Moberly First Nation in its lawsuit aimed at stopping Site C. (Sage Legal)

In the meantime, the parties will continue to prepare for the 2022 court dates.

The latest figure on the cost of the dam is $10.7 billion, in a billions-over-budget project that the premier says will proceed. When complete, it would power the equivalent of 450,000 homes a year, though use of Site C's electricity remains a point of debate.

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