Residents to get a look at polygeneration plant

Ontario Hydro Crisis highlights soaring electricity rates, costly subsidies, nuclear refurbishments, and stalled renewables in Ontario. Policy missteps, weak planning, and rising natural gas emissions burden ratepayers while energy efficiency and storage remain underused.

Key Points

High power costs and subsidies from policy errors, nuclear refurbishments, stalled efficiency and renewables in Ontario.

✅ $5.6B yearly subsidy masks electricity rates and deficits

✅ Nuclear refurbishments embed rising costs for decades

✅ Efficiency, storage, and DERs stalled amid weak planning

By Mark Winfield

While the troubled Site C and Muskrat Falls hydroelectric dam projects in B.C. and Newfoundland and Labrador have drawn a great deal of national attention over the past few months, Ontario has quietly been having a hydro crisis of its own.

One of the central promises in the 2018 platform of the Ontario Progressive Conservative party was to “clean up the hydro mess,” and then-PC leader Doug Ford vowed to fire Hydro One's leadership as part of that effort. There certainly is a mess, with the costs of subsidies taken from general provincial revenues to artificially lower hydro rates nearing $7 billion annually. That is a level approaching the province’s total pre-COVID-19 annual deficit. After only two years, that will also exceed total expected cost overruns of the Site C and Muskrat Falls projects, currently estimated at $12 billion ($6 billion each).

There is no doubt that Doug Ford’s government inherited a significant mess around the province’s electricity system from the previous Liberal governments of former premiers Dalton McGuinty and Kathleen Wynne. But the Ford government has also demonstrated a remarkable capacity for undoing the things its predecessors had managed to get right while doubling down on their mistakes.

The Liberals did have some significant achievements. Most notably: coal-fired electricity generation, which constituted 25 per cent of the province’s electricity supply in the early 2000s, was phased out in 2014. The phaseout dramatically improved air quality in the province. There was also a significant growth in renewable energy production. From  virtually zero in 2003, the province installed 4,500 MW of wind-powered generation, and 450 MW of solar photovoltaic by 2018, a total capacity more than double that of the Sir Adam Beck Generating Stations at Niagara Falls.

At the same time, public concerns over rising hydro rates flowing from a major reconstruction of the province’s electricity system from 2003 onwards became a central political issue in the province. But rather than reconsider the role of the key drivers of the continuing rate increases – namely the massively expensive and risky refurbishments of the Darlington and Bruce nuclear facilities, the Liberals adopted a financially ruinous Fair Hydro Plan. The central feature of the 2017 plan was a short-term 25 per cent reduction in hydro rates, financed by removing the provincial portion of the HST from hydro bills, and by extending the amortization period for capital projects within the system. The total cost of the plan in terms of lost revenues and financing costs has been estimated in excess of $40 billion over 29 years, with the burden largely falling on future ratepayers and taxpayers.

Decision-making around the electricity system became deeply politicized, and a secret cabinet forecast of soaring prices intensified public debate across Ontario. Legislation adopted by the Wynne government in 2016 eliminated the requirement for the development of system plans to be subject to any form of meaningful regulatory oversight or review. Instead, the system was guided through directives from the provincial cabinet. Major investments like the Darlington and Bruce refurbishments proceeded without meaningful, public, external reviews of their feasibility, costs or alternatives.

The Ford government proceeded to add more layers to these troubles. The province’s relatively comprehensive framework for energy efficiency was effectively dismantled in March, 2019, with little meaningful replacement. That was despite strong evidence that energy efficiency offered the most cost-effective strategy for reducing greenhouse gas emissions and electricity costs.

The Ford government basically retained the Fair Hydro Plan and promised further rate reductions, later tabling legislation to lower electricity rates as well. To its credit, the government did take steps to clarify real costs of the plan. Last year, these were revealed to amount to a de facto $5.6 billion-per-year subsidy coming from general revenues, and rising. That constituted the major portion of the province’s $7.4 billion pre-COVID-19 deficit. The financial hole was deepened further through November’s financial statement, with the addition of a further $1.3 billion subsidy to commercial and industrial consumers. The numbers can only get worse as the costs of the Darlington and Bruce refurbishments become embedded more fully into electricity rates.

The government also quietly dispensed with the last public vestige of an energy planning framework, relieving itself of the requirement to produce a Long-Term Energy Plan every three years. The next plan would normally have been due next month, in February.

Even the gains from the 2014 phaseout of coal-fired electricity are at risk. Major increases are projected in emissions of greenhouse gases, smog-causing nitrogen oxides and particulate matter from natural gas-fired power plants as the plants are run to cover electricity needs during the Bruce and Darlington refurbishments over the next decade. These developments could erode as much as 40 per cent of the improvements in air quality and greenhouse gas emission gained through the coal phaseout.

The province’s activities around renewable energy, energy storage and distributed energy resources are at a standstill, with exception of a few experimental “sandbox” projects, while other jurisdictions face profound electricity-sector change and adapt. Globally, these technologies are seen as the leading edge of energy-system development and decarbonization. Ontario seems to have chosen to make itself an energy innovation wasteland instead.

The overall result is a system with little or no space for innovation that is embedding ever-higher costs while trying to disguise those costs at enormous expense to the provincial treasury and still failing to provide effective relief to low-income electricity consumers.

The decline in electricity demand associated with the COVID-19 pandemic, along with the introduction of a temporary recovery rate for electricity, gives the province an opportunity to step back and consider its next steps with the electricity system. A phaseout of the Fair Hydro Plan electricity-rate reduction and its replacement with a more cost-effective strategy of targeted relief aimed at those most heavily burdened by rising hydro rates, particularly rural and low-income consumers, as reconnection efforts for nonpayment have underscored the hardship faced by many households, would be a good place to start.

Next, the province needs to conduct a comprehensive, public review of electricity options available to it, including additional renewables – the costs of which have fallen dramatically over the past decade – distributed energy resources, hydro imports from Quebec and energy efficiency before proceeding with further nuclear refurbishments.

In the longer term, a transparent, evidence-based process for electricity system planning needs to be established – one that is subject to substantive public and regulatory oversight and review. Finally, the province needs to establish a new organization to be called Energy Efficiency Ontario to revive its efforts around energy efficiency, developing a comprehensive energy-efficiency strategy for the province, covering electricity and natural gas use, and addressing the needs of marginalized communities.

Without these kinds of steps, the province seems destined to continue to lurch from contradictory decision after contradictory decision as the economic and environmental costs of the system’s existing trajectory continue to rise.

Mark Winfield is a professor of environmental studies at York University and co-chair of the university’s Sustainable Energy Initiative.

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Hydro Quebec Power Consumption Record surges amid extreme cold, peak demand, and grid stress, as Hydro-Quebec urges energy conservation, load management, and reduced heating during morning and evening peaks across Montreal and southern Quebec.

Key Points

Quebec's grid hit 40,300 MW during an extreme cold snap, setting a new record and prompting conservation appeals.

✅ Lower thermostats 1-2 C in unused rooms during peak hours

✅ Delay dishwashers, dryers, and hot water use to off-peak

✅ Peak windows: 6-9 a.m. and 4-8 p.m.; import power if needed

Hydro Quebec says it has once again set a new record for power consumption, echoing record-breaking demand in B.C. in 2021 as extreme cold grips much of the province.

An extreme cold warning has been in effect across southern Quebec since Friday morning, straining the system, just as Calgary's electricity use soared during a frigid February, as Quebecers juggle staying warm and working from home.

Hydro Québec recorded consumption levels reaching 40,300 megawatts as of 8 a.m. Friday, breaking a previous record of 39,000 MW (with B.C. electricity demand hit an all-time high during a similar cold snap) that was broken during another cold snap on Jan 11. 

The publicly owned utility is now asking Quebecers to reduce their electricity consumption as much as possible today and tomorrow, a move consistent with clean electricity goals under federal climate pledges, predicting earlier in the morning the province would again reach an all-time high.

Reducing heating by just one or two degrees, especially in rooms that aren't being used, is one step that people can take to limit their consumption. They can also avoid using large appliances like the dishwasher and clothing dryer as often, and shortening the use of hot water. 

"They're small actions, but across millions of clients, it makes a difference," said Cendrix Bouchard, a spokesperson with Hydro Québec, while speaking with Tout un matin.

"We understand that asking this may pose challenges for some who are home throughout the day because they are working remotely, but if people are able to contribute, we appreciate it."

The best time to try and limit electricity usage is in the morning and evening, when electricity usage tends to peak, Bouchard said.

The province can import electricity from other regions if Quebec's system reaches its limits, even as the utility pursues selling to the United States as part of its long-term strategy, he added.

Temperatures dropped to –24 C in Montreal at 7 a.m., with a wind chill of –29 C. 

It will get colder across the south of the province through the evening and wind chills are expected to make it feel as cold as – 40 until Saturday morning, Environment Canada warned.

Those spending time outdoors are at a higher risk of frostbite and hypothermia.

"Frostbite can develop within minutes on exposed skin, especially with wind chill," Environment Canada said.

Conserving energy
Hydro-Québec has signed up 160,000 clients to a flexible billing plan similar to BC Hydro's winter payment plan that allows them to pay less for energy — as long as they use it during non-peak periods.

Quebec's energy regulator, the Régie de l'énergie, also forces crypto-currency mining operations to shut down for some hours  on peak-demand days, a topic where BC Hydro's approach to crypto mining has also drawn attention, Bouchard said.

Hydro-Québec says the highest consumption periods are usually between 6 a.m.-9 a.m. and 4 p.m.-8 p.m.

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Tesla Electric UK Expansion signals retail energy entry, leveraging Powerwall VPPs for grid services, dynamic pricing, and energy trading, building on Texas success and Octopus Energy ties to buy and sell electricity automatically.

Key Points

Tesla's plan to launch Tesla Electric in the UK, using Powerwall VPPs to retail energy, trade power, and hedge peaks.

✅ Retail energy model built on Powerwall VPP aggregation

✅ Automated buy-sell arbitrage with dynamic pricing

✅ Leverages prior UK approval and Octopus Energy ties

According to a new job posting, Tesla Electric, Tesla’s new electric utility division, is preparing to expand in the United Kingdom as regions such as California grid planners look to electric vehicles for stability to manage demand.

Late last year, after gaining experience through its virtual power plants (VPPs), including response during California blackouts that pressured the grid, Tesla took things a step further with the launch of “Tesla Electric.”

Instead of reacting to specific “events” and providing services to your local electric utilities through demand response programs, as Tesla Powerwall owners have done in VPPs in California, Tesla Electric is actively and automatically buying and selling electricity for Tesla Powerwall owners – providing a buffer against peak prices.

The company is essentially becoming an energy retailer, aligning with a major future for its energy business envisioned by leadership.

Tesla Electric is currently only available to Powerwall owners in Texas, but the company has plans to expand its products through this new division.

We recently reported on Tesla Electric customers in Texas making as much as $150 a day selling electricity back to the grid through the program.

Now Tesla is looking to expand Tesla Electric to the UK, where grid capacity for rising EV demand remains a key consideration.

The company has listed a new job posting for a role called “Head of Operations, Tesla Electric – Retail Energy.”

This has been in the works for a while now. Tesla used to have a partnership with Octopus Energy in the UK for special electricity rates for its owners, during a period when UK EV inquiries surged amid a fuel supply crisis, but it seemed to be a stepping stone before it would itself become an energy provider in the market.

In 2020, Tesla was officially approved as an electricity retailer in the UK. Now it looks like Tesla is going to use this approval with the launch of Tesla Electric.
 

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COVID-19 Impact on U.S. Electricity Consumption shows commercial and industrial demand dropped as residential use rose, with flattened peak loads, weekday-weekend convergence, Texas hourly data, and energy demand as a real-time economic indicator.

Key Points

It reduced commercial and industrial demand while raising residential use, shifting peaks and weekday patterns.

✅ Commercial electricity down 12%; industrial down 14% in Q2 2020

✅ Residential use up 10% amid work-from-home and lockdowns

✅ Peaks flattened; weekday-weekend loads converged in Texas

This is an important turning point for the United States. We have a long road ahead. But one of the reasons I’m optimistic about Biden-Harris is that we will once again have an administration that believes in science.

To embrace this return to science, I want to write today about a fascinating new working paper by Tufts economist Steve Cicala.

Professor Cicala has been studying the effect of Covid on electricity consumption since back in March, when the Wall Street Journal picked up his work documenting an 18% decrease in electricity consumption in Italy.

The new work, focused on the United States, is particularly compelling because it uses data that allows him to distinguish between residential, commercial, and industrial sectors, against a backdrop of declining U.S. electricity sales over recent years.

Without further ado, here are four facts he uncovers about Covid and U.S. electricity demand during COVID-19 and consumption.

Fact #1: Firms Are Using Less
U.S. commercial electricity consumption fell 12% during the second quarter of 2020. U.S. industrial electricity consumption fell 14% over the same period.

This makes sense. The second quarter was by some measures, the worst quarter for the U.S. economy in over 145 years!

Economic activity shrank. Schools closed. Offices closed. Factories closed. Restaurants closed. Malls closed. Even health care offices closed as patients delayed going to the dentist and other routine care. All this means less heating and cooling, less lighting, less refrigeration, less power for computers and other office equipment, less everything.

The decrease in the industrial sector is a little more surprising. My impression had been that the industrial sector had not fallen as far as commercial, but amid broader disruptions in coal and nuclear power that strained parts of the energy economy, the patterns for both sectors are quite similar with the decline peaking in May and then partially rebounding by July. The paper also shows that areas with higher unemployment rates experienced larger declines in both sectors.

Fact #2: Households Are Using More
While firms are using less, households are using more. U.S. residential electricity consumption increased 10% during the second quarter of 2020. Consumption surged during March, April, and May, a reflection of the lockdown lifestyle many adopted, and then leveled off in June and July – with much less of the rebound observed on the commercial/industrial side.

This pattern makes sense, too. In Professor Cicala’s words, “people are spending an inordinate amount of time at home”. Many of us switched over to working from home almost immediately, and haven’t looked back. This means more air conditioning, more running the dishwasher, more CNN (especially last week), more Zoom, and so on.

The paper also examines the correlates of the decline. Areas in the U.S. where more people can work from home experienced larger increases. Unemployment rates, however, are almost completely uncorrelated with the increase.

Fact #3: Firms are Less Peaky
The paper next turns to a novel dataset from Texas, where Texas grid reliability is under active discussion, that makes it possible to measure hourly electricity consumption by sector.

As the figure above illustrates, the biggest declines in commercial/industrial electricity consumption have occurred Monday through Friday between 9AM and 5PM.

The dashed line shows the pattern during 2019. Notice the large spikes in electricity consumption during business hours. The solid line shows the pattern during 2020. Much smaller spikes during business hours.

Fact #4: Everyday is Like Sunday
Finally, we have what I would like to nominate as the “Energy Figure of the Year”.

Again, start with the pattern for 2019, reflected by the dashed line. Prior to Covid, Texas households used a lot more electricity on Saturdays and Sundays.

Then along comes Covid, and turned every day into the weekend. Residential electricity consumption in Texas during business hours Monday-Friday is up 16%(!).

In the pattern for 2020, it isn’t easy to distinguish weekends from weekdays. If you feel like weekdays and weekends are becoming a big blur – you are not alone.

Conclusion
Researchers are increasingly thinking about electricity consumption as a real-time indicator of economic activity, even as flat electricity demand complicates utility planning and investment. This is an intriguing idea, but Professor Cicala’s new paper shows that it is important to look sector-by-sector.

While commercial and industrial consumption indeed seem to measure the strength of an economy, residential consumption has been sharply countercylical – increasing exactly when people are not at work and not at school.

These large changes in behavior are specific to the pandemic. Still, with the increased blurring of home and non-home activities we may look back on 2020 as a key turning point in how we think about these three sectors of the economy.

More broadly, Professor Cicala’s paper highlights the value of social science research. We need facts, data, and yes, science, if we are to understand the economy and craft effective policies on energy insecurity and shut-offs as well.

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California Electricity Reserve Mandate requires 3.3 GW of new capacity to bolster grid reliability amid solar power volatility, peak demand, and wildfire-driven blackouts, as CPUC directs PG&E, Edison, and Sempra to procure resource adequacy.

Key Points

A CPUC order for utilities to add 3.3 GW of reserves, safeguarding grid reliability during variable renewables and peaks

✅ 3.3 GW procurement to meet resource adequacy targets

✅ Focus on grid reliability during peak evening demand

✅ Prioritizes renewables, storage; limits new fossil builds

As if California doesn’t have enough problems with its electric service, now state regulators warn the state may be short on power supplies by 2021 if utilities don’t start lining up new resources now.

In the hopes of heading off a shortfall as America goes electric, the California Public Utilities Commission has ordered the state’s electricity providers to secure 3.3 additional gigawatts of reserve supplies. That’s enough to power roughly 2.5 million homes. Half of it must be in place by 2021 and the rest by August 2023.

The move comes as California is already struggling to accommodate increasingly large amounts of solar power that regularly send electricity prices plunging below zero and force other generators offline so the region’s grid doesn’t overload. The state is also still reeling from a series of deliberate mass blackouts that utilities imposed last month to keep their power lines from sparking wildfires amid strong winds. And its largest power company, PG&E Corp., went bankrupt in January.

Now as natural gas-fired power plants retire under the state’s climate policies, officials are warning the state could run short on electricity on hot evenings, when solar production fades and commuters get home and crank up their air conditioners. “We have fewer resources that can be quickly turned on that can meet those peaks,” utilities commission member Liane Randolph said Thursday before the panel approved the order to beef up reserves.

The 3.3 gigawatts that utilities must line up is in addition to a state rule requiring them to sign contracts for 15% more electricity than they expect to need. Some critics question the need for added supplies, particularly after the state went on a plant-building boom in the 2000s.

But California’s grid managers say the risk of a shortfall is real and could be as high as 4.7 gigawatts, especially during heat waves that test the grid again. Mark Rothleder, with the California Independent System Operator, said the 15% cushion is a holdover from the days before big solar and wind farms made the grid more volatile. Now it may need to be increased, he said.

“We’re not in that world anymore,” said Rothleder, the operator’s vice president of state regulatory affairs. “The complexity of the system and the resources we have now are much different.”

The state’s three major utilities, PG&E, Edison International and Sempra Energy, will be largely responsible for securing new supplies. The commission banned fossil fuels from being used at any new power generators built to meet the requirement — though it left the door open for expansions at existing ones.

Some analysts argue California is exporting its energy policies to Western states, making electricity more costly and less reliable.

PG&E said in an emailed statement that it was pleased the commission didn’t adopt an earlier proposal to require 4 gigawatts of additional resources. Edison similarly said it was “supportive.” Sempra didn’t immediately respond with comment.

Extending Deadlines

The pending plant closures are being hastened by a 2020 deadline requiring California’s coastal generators to stop using aging seawater-cooling systems. Some gas-fired power plants have said they’ll simply close instead of installing costly new cooling systems. So the commission on Thursday also asked California water regulators to extend the deadline for five plants.

The Sierra Club, meanwhile, called on regulators to turn away from fossil fuels altogether, saying their decision Thursday “sets California back on its progress toward a clean energy future.”

The move to push back the deadline also faces opposition from neighboring towns. Redondo Beach Mayor Bill Brand, whose city is home to one of the plants in line for an extension, told the commission it wasn’t necessary, since California utilities already have plenty of electricity reserves.

“It’s just piling on to that reserve margin,” Brand said.

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Calistoga Resiliency Centre Microgrid delivers grid resilience via green hydrogen and BESS, providing island-mode backup during PSPS events, wildfire risk, and outages, with black-start and grid-forming capabilities for reliable community power.

Key Points

A hybrid green hydrogen and BESS facility ensuring resilient, islanded power for Calistoga during PSPS and outages.

✅ 293 MWh capacity with 8.5 MW peak for critical backup

✅ Hybrid lithium-ion BESS plus green hydrogen fuel cells

✅ Island mode with black-start and grid-forming support

Energy Vault, a prominent energy storage and technology company known for its gravity storage, recently secured US$28 million in project financing for its innovative Calistoga Resiliency Centre (CRC) in California. This funding will enable the development of a microgrid powered by a unique combination of green hydrogen and battery energy storage systems (BESS), marking a significant step forward in enhancing grid resilience in the face of natural disasters such as wildfires.

Located in California's fire-prone regions, the CRC is designed to provide critical backup power during Public Safety Power Shutoff (PSPS) events—periods when utility companies proactively cut power to prevent wildfires. These events can leave communities without electricity for extended periods, making the need for reliable, independent power sources more urgent as many utilities see benefits in energy storage today. The CRC, with a capacity of 293 MWh and a peak output of 8.5 MW, will ensure that the Calistoga community maintains power even when the grid is disconnected.

The CRC features an integrated hybrid system that combines lithium-ion batteries and green hydrogen fuel cells, even as some grid-scale projects adopt vanadium flow batteries for long-duration needs. During a PSPS event or other grid outages, the system will operate in "island mode," using hydrogen to generate electricity. This setup not only guarantees power supply but also contributes to grid stability by supporting black-start and grid-forming functions. Energy Vault's proprietary B-VAULT DC battery technology complements the hydrogen fuel cells, enhancing the overall performance and resilience of the microgrid.

One of the key aspects of the CRC project is the utilization of green hydrogen. Unlike traditional hydrogen, which is often produced using fossil fuels, green hydrogen is generated through renewable energy sources like solar or wind power, with large-scale initiatives such as British Columbia hydrogen project accelerating supply, making it a cleaner and more sustainable alternative. This aligns with California’s ambitious clean energy goals and is expected to reduce the carbon footprint of the region’s energy infrastructure.

The CRC project also sets a precedent for future hybrid microgrid deployments across California and other wildfire-prone areas, with utilities like SDG&E Emerald Storage highlighting growing adoption. Energy Vault has positioned the CRC as a model for scalable, utility-scale microgrids that can be adapted to various locations facing similar challenges. Following the success of this project, Energy Vault is expanding its portfolio with additional projects in Texas, where it anticipates securing up to US$25 million in financing.

The funding for the CRC also includes the sale of an investment tax credit (ITC), a key component of the financing structure that helps make such ambitious projects financially viable. This structure is crucial as it allows companies to leverage government incentives to offset development costs, including CEC long-duration storage funding, thus encouraging further investment in green energy infrastructure.

Despite some skepticism regarding the transportation of hydrogen rather than producing it onsite, the project has garnered strong support. California’s Public Utilities Commission (CPUC) acknowledged the potential risks of transporting green hydrogen but emphasized that it is still preferable to using more harmful fuel sources. This recognition is important as it validates Energy Vault’s approach to using hydrogen as part of a broader strategy to transition to clean, reliable energy solutions.

Energy Vault's shift from its traditional gravity-based energy storage systems to battery energy storage systems, such as BESS in New York, reflects the company's adaptation to the growing demand for versatile, efficient energy solutions. The hybrid approach of combining BESS with green hydrogen represents an innovative way to address the challenges of energy storage, especially in regions vulnerable to natural disasters and power outages.

As the CRC nears mechanical completion and aims for full commercial operations by Q2 2025, it is poised to become a critical part of California’s grid resilience strategy. The microgrid's ability to function autonomously during emergencies will provide invaluable benefits not only to Calistoga but also to other communities that may face similar grid disruptions in the future.

Energy Vault’s US$28 million financing for the Calistoga Resiliency Centre marks a significant milestone in the development of hybrid microgrids that combine the power of green hydrogen and battery energy storage. This project exemplifies the future of energy resilience, showcasing a forward-thinking approach to mitigating the impact of natural disasters and ensuring a reliable, sustainable energy future for communities at risk. With its innovative use of renewable energy sources and cutting-edge technology, the CRC sets a strong example for future energy storage projects worldwide.

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