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California Income-Based Electricity Rates propose a fixed monthly fee set by income as utilities and the CPUC weigh progressive pricing, aiming to cut low-income bills while PG&E, SCE, and SDG&E retain usage-based charges.

Key Points

CPUC plan adds income-tiered fixed fees to lower low-income bills while keeping per-kWh usage charges.

✅ Adds fixed monthly fees by income to complement per-kWh charges

✅ Cuts bills for low-income households; higher earners pay more

✅ Utilities say revenue neutral; conservation signals preserved

California’s electric bills — already some of the highest in the nation — are rising as electricity prices soar across the state, but regulators are debating a new plan to charge customers based on their income level. 

Typically what you pay for electricity depends on how much you use. But the state’s three largest electric utilities — Southern California Edison Company, Pacific Gas and Electric Company and San Diego Gas & Electric Company — have proposed a plan to charge customers not just for how much energy they use, but also based on their household income, moving toward income-based flat-fee utility bills over time. Their proposal is one of several state regulators received designed to accommodate a new law to make energy less costly for California’s lowest-income customers.

Some state Republican lawmakers are warning the changes could produce unintended results, such as weakening incentives to conserve electricity or raising costs for customers using solar energy, and some have introduced a plan to overturn the charges in the Legislature.

But the utility companies say the measure would reduce electricity bills for the lowest income customers. Those residents would save about $300 per year, utilities estimate.

California households earning more than $180,000 a year would end up paying an average of $500 more a year on their electricity bills, according to the proposal from utility companies. 

The California Public Utilities Commission’s deadline for deciding on the suggested changes is July 1, 2024, as regulators face calls for action from consumers and advocates. The proposals come at a time when many moderate and low-income families are being priced out of California by rising housing costs.  

Who wants to change the fee structure?
Lawmakers passed and Gov. Gavin Newsom signed a comprehensive energy bill last summer that mandates restructuring electricity pricing across the state. 

The Legislature passed the measure in a “trailer-bill” process that limited deliberation. Included in the 21,000-word law are a few sentences requiring the public utilities commission to establish a “fixed monthly fee” based on each customer’s household income. 

A similar idea was first proposed in 2021 by researchers at UC Berkeley and the nonprofit thinktank Next 10. Their main recommendation was to split utility costs into two buckets. Fixed charges, which everyone has to pay just to be connected to the energy grid, would be based on income levels. Variable charges would depend on how much electricity you use.

Utilities say that part of customers’ bills still will be based on usage, but the other portion will reduce costs for lower- and middle-income customers, who “pay a greater percentage of their income towards their electricity bill relative to higher income customers,” the utilities argued in a recent filing. 

They said the current billing system is unjust, regressive and fails to recognize differences in energy usage among households,

“When we were putting together the reform proposal, front and center in our mind were customers who live paycheck to paycheck, who struggle to pay for essentials such as energy, housing and food,” Caroline Winn, CEO of San Diego Gas & Electric in a statement. 

The utilities say in their proposal that the changes likely would not reduce or increase their revenues.

James Sallee, an associate professor at UC Berkeley, said the utilities’ prior system of billing customers mostly by measuring their electric use to pay for what are essentially fixed costs for power is inefficient and regressive. 

The proposed changes “will shift the burden, on average, to a more progressive system that recovers more from higher income households and less from lower income households,” he said.

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California Net Zero Grid Investment will fuel electrification, renewable energy buildout, EV adoption, and grid modernization, boosting utilities, solar, and storage, while policy, IRA incentives, and transmission upgrades drive reliability and long-term rate base growth.

Key Points

Funding to electrify sectors and modernize the grid, scaling renewables, EVs, and storage to meet 2045 net zero goals.

✅ $370B over 22 years to meet 2045 net zero target

✅ Utilities lead gains via grid modernization and rate base growth

✅ EVs, solar, storage scale; IRA credits offset costs

$370 billion: That’s the investment Edison International CEO Pedro Pizarro says is needed for California’s power grid to meet the state’s “net zero” goal for CO2 emissions by 2045.

Getting there will require replacing fossil fuels with electricity in transportation, HVAC systems for buildings and industrial processes. Combined with population growth and data demand potentially augmented by artificial intelligence, that adds up to an 82 percent increase in electricity demand over 22 years, or 3 percent annually, and a potential looming shortage if buildout lags.

California’s plans also call for phasing out fossil fuel generation in the state, despite ongoing dependence on fossil power during peaks. And presumably, its last nuclear plant—PG&E Corp’s (PCG) Diablo Canyon—will be eventually be shuttered as well. So getting there also means trebling the state’s renewable energy generation and doubling usage of rooftop solar.

Assuming this investment is made, it’s relatively easy to put together a list of beneficiaries. Electric vehicles hit 20 percent market share in the state in Q2, even as pandemic-era demand shifts complicate load forecasting. And while competition from manufacturers has increased, leading manufacturers like Tesla TSLA -3% Inc (TSLA) can look forward to rising sales for some time—though that’s more than priced in for Elon Musk’s company at 65 times expected next 12 months earnings.

In the past year, California regulators have dialed back net metering through pricing changes affecting compensation, a subsidy previously paying rooftop solar owners premium prices for power sold back to the grid. That’s hit share prices of SunPower Corp (SPWR) and Sunrun Inc (RUN) quite hard, by further undermining business plans yet to demonstrate consistent profitability.

Nonetheless, these companies too can expect robust sales growth, as global prices for solar components drop and Inflation Reduction Act tax credits at least somewhat offset higher interest rates. And the combination of IRA tax credits and U.S. tariff walls will continue to boost sales at solar manufacturers like JinkoSolar Holding (JKS).

The surest, biggest beneficiaries of California’s drive to Net Zero are the utilities, reflecting broader utility trends in grid modernization, with investment increasing earnings and dividends. And as the state’s largest pure electric company, Edison has the clearest path.

Edison is currently requesting California regulators OK recovery over a 30-year period of $2.4 billion in losses related to 2017 wildfires. Assuming a amicable decision by early next year, management can then turn its attention to upgrading the grid. That investment is expected to generate long-term rate base growth of 8 percent at year, fueling 5 to 7 percent annual earnings growth through 2028 with commensurate dividend increases.

That’s a strong value proposition Edison stock, with trades at just 14 times expected next 12 months earnings. The yield of roughly 4.4 percent at current prices was increased 5.4 percent this year and is headed for a similar boost in December.

When California deregulated electricity in 1996, it required utilities with rare exceptions to divest their power generation. As a result, Edison’s growth opportunity is 100 percent upgrading its transmission and distribution grid. And its projects can typically be proposed, sited, permitted and built in less than a year, limiting risk of cost overruns to ensure regulatory approval and strong investment returns.

Edison’s investment plan is also pretty much immune to an unlikely backtracking on Net Zero goals by the state. And the company has a cost argument as well: Dr Pizarro cites U.S. Department of Energy and Department of Transportation data to project inflation-adjusted savings of 40 percent in California’s total customer energy bills from full electrification.

There’s even a reason to believe 40 percent savings will prove conservative. Mainly, gasoline currently accounts for a bit more than half energy expenditures. And after a more than 10-year global oil and gas investment drought, supplies are likely get tighter and prices possibly much higher in coming years.

Of course, those savings will only show up after significant investment is made. At this point, no major utility system in the world runs on 100 percent renewable energy, and California’s blackout politics underscore how reliability concerns shape deployment. And the magnitude of storage technology needed to overcome intermittency in solar and wind generation is not currently available let alone affordable, though both cost and efficiency are advancing.

Taking EVs from 20 to 100 percent of California’s new vehicle sales calls for a similar leap in efficiency and cost, even with generous federal and state subsidy. And while technology to fully electrify buildings and homes is there, economically retrofitting statewide is almost certainly going to be a slog.

At the end of the day, political will is likely to be as important as future technological advance for how much of Pizarro’s $370 billion actually gets spent. And the same will be true across the U.S., with state governments and regulators still by and large calling the shots for how electricity gets generated, transmitted and distributed—as well as who pays for it and how much, even as California’s exported policies influence Western markets.

Ironically, the one state where investors don’t need to worry about renewable energy’s prospects is one of the currently reddest politically. That’s Florida, where NextEra Energy NEE +2.8% (NEE) and other utilities can dramatically cut costs to customers and boost reliability by deploying solar and energy storage.

You won’t hear management asserting it can run the Sunshine State on 100 percent renewable energy, as utilities and regulators do in some of the bluer parts of the country. But by demonstrating the cost and reliability argument for solar deployment, NextEra is also making the case why its stock is America’s highest percentage bet on renewables’ growth—particularly at a time when all things energy are unfortunately becoming increasingly, intensely political.

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Germany Energy Transition faces offshore wind expansion, grid bottlenecks, and North-South transmission delays, while Nord Stream 2 boosts Russian gas reliance and lignite coal persists amid a nuclear phaseout and rising re-dispatch costs.

Key Points

Germanys shift to renewables faces grid delays, boosting gas via Nord Stream 2 and extending lignite coal use.

✅ Offshore wind grows, but grid congestion curtails turbines.

✅ Nord Stream 2 expands Russian gas supply to German industry.

✅ Lignite coal persists, raising emissions amid nuclear exit.

On a blazing hot August day on Germany’s Baltic Sea coast, a few hundred tourists skip the beach to visit the “Fascination Offshore Wind” exhibition, held in the port of Mukran at the Arkona wind park. They stand facing the sea, gawking at white fiberglass blades, which at 250 feet are longer than the wingspan of a 747 aircraft. Those blades, they’re told, will soon be spinning atop 60 wind-turbine towers bolted to concrete pilings driven deep into the seabed 20 miles offshore. By early 2019, Arkona is expected to generate 385 megawatts, enough electricity to power 400,000 homes.

“We really would like to give the public an idea of what we are going to do here,” says Silke Steen, a manager at Arkona. “To let them say, ‘Wow, impressive!’”

Had the tourists turned their backs to the sea and faced inland, they would have taken in an equally monumental sight, though this one isn’t on the day’s agenda: giant steel pipes coated in gray concrete, stacked five high and laid out in long rows on a stretch of dirt. The port manager tells me that the rows of 40-foot-long, 4-foot-thick pipes are so big that they can be seen from outer space. They are destined for the Nord Stream 2 pipeline, a colossus that, when completed next year, will extend nearly 800 miles from Russia to Germany, bringing twice the amount of gas that a current pipeline carries.

The two projects, whose cargo yards are within a few hundred feet of each other, provide a contrast between Germany’s dream of renewable energy and the political realities of cheap Russian gas. In 2010, Germany announced an ambitious goal of generating 80 percent of its electricity from renewable sources by 2050. In 2011, it doubled down on the commitment by deciding to shut down every last nuclear power plant in the country by 2022, as part of a broader coal and nuclear phaseout strategy embraced by policymakers. The German government has paid more than $600 billion to citizens and companies that generate solar and wind power. As a result, the generating capacity from renewable sources has soared: In 2017, a third of the nation’s electricity came from wind, solar, hydropower and biogas, up from 3.6 percent in 1990.

But Germany’s lofty vision has run into a gritty reality: Replacing fossil fuels and nuclear power in one of the largest industrial nations in the world is politically more difficult and expensive than planners thought. It has forced Germany to put the brakes on its ambitious renewables program, ramp up its investments in fossil fuels, amid a renewed nuclear option debate over climate strategy, and, to some extent, put its leadership role in the fight against climate change on hold.

The trouble lies with Germany’s electricity grid. Solar and wind power call for more complex and expensive distribution networks than conventional large power plants do. “What the Germans were good at was getting new technology into the market, like wind and solar power,” said Arne Jungjohann, author of Energy Democracy: Germany’s ENERGIEWENDE to Renewables. To achieve its goals, “Germany needs to overhaul its whole grid.”

The North-South Conundrum

The boom in wind power has created an unanticipated mismatch between supply and demand. Big wind turbines, especially offshore plants such as Arkona, produce powerful, concentrated gusts of energy. That’s good when the factory that needs that energy is nearby and the wind kicks up during working hours. It’s another matter when factories are hundreds of miles away. In Germany, wind farms tend to be located in the blustery north. Many of the nation’s big factories lie in the south, which also happens to be where most of the country’s nuclear plants are being mothballed.

Getting that power from north to south is problematic. On windy days, northern wind farms generate too much energy for the grid to handle. Power lines get overloaded. To cope, grid operators ask wind farms to disconnect their turbines from the grid—those elegant blades that tourists so admired sit idle. To ensure a supply of power, operators employ backup generators at great expense. These so-called re-dispatching costs ran to 1.4 billion euros ($1.6 billion) last year.

The solution is to build more power transmission lines to take the excess wind from northern wind farms to southern factories. A grid expansion project is underway to do exactly that. Nearly 5,000 miles of new transmission lines, at a cost of billions of euros, will be paid for by utility customers. So far, less than a fifth of the lines have been built.

The grid expansion is “catastrophically behind schedule,” Energy Minister Peter Altmaier told the Handelsblatt business newspaper in August. Among the setbacks: citizens living along the route of four high-voltage power lines have demanded the cables be buried underground, which has added to the time and expense. The lines won’t be finished before 2025—three years after Germany’s nuclear shutdown is due to be completed.

With this backlog, the government has put the brakes on wind power, reducing the number of new contracts for farms and curtailing the amount it pays for renewable energy. “In the past, we have focused too much on the mere expansion of renewable energy capacity,” Joachim Pfeiffer, a spokesman for the Christian Democratic Union, wrote to Newsweek. “We failed to synchronize this expansion of generation with grid expansion.”

Advocates of renewables are up in arms, accusing the government of suffocating their industry and making planning impossible. Thousands of people lost their jobs in the wind industry, according to Wolfram Axthelm, CEO of the German Wind Energy Association. “For 2019 and 2020, we see a highly problematic situation for the industry,” he wrote in an email.

Fueling the Gap

Nord Stream 2, by contrast, is proceeding according to schedule. A beige and black barge, Castoro 10, hauls dozens of lengths of giant pipe off Germany’s Baltic Sea coast, where a welding machine connects them for lowering onto the seabed. The $11 billion project is funded by Russian state gas monopoly Gazprom and five European investors, at no direct cost to the German taxpayer. It is slated to cross the territorial waters of five countries—Germany, Russia, Finland, Sweden and Denmark. All but Denmark have approved the route. “We have good reason to believe that after four governments said yes, that Denmark will also approve the pipeline,” says Nord Stream 2 spokesman Jens Mueller.

Construction of the pipeline off Finland began in September, and the gas is expected to start flowing in late 2019, giving Russia leverage to increase its share of the European gas market. It already provides a third of the gas used in the EU and will likely provide more after the Netherlands stops its gas production in 2030. President Donald Trump has called the pipeline “a very bad thing for NATO” and said that “Germany is totally controlled by Russia.” U.S. senators have threatened sanctions against companies involved in the project. Ukraine and Poland are concerned the new pipeline will make older pipelines in their territories irrelevant.

German leaders are also wary of dependence on Russia but are under considerable pressure to deliver energy to industry. Indeed, among the pipeline’s investors are German companies that want to run their factories, like BASF’s Wintershall subsidiary and Uniper, the German utility. “It’s not that Germany is naive,” says Kirsten Westphal, an energy expert at the German Institute for International and Security Affairs. It’s just pragmatic. “Economically, the judgment is that yes, this gas will be needed, we have an import gap to fill.”

The electricity transmission problem has also opened an opportunity for lignite coal, as coal generation in Germany remains significant, the most carbon-intensive fuel available and the source for nearly a quarter of Germany’s power. Mining companies are expanding their operations in coal-rich regions to strip out the fuel while it is still relevant. In the village of Pödelwitz, 155 miles south of Berlin, most houses feature a white sign with the logo of Mibrag, the German mining giant, which has paid nearly all the 130 residents to relocate. The company plans to level the village and scrape lignite that lies below the soil.

A resurgence in coal helped raise carbon emissions in 2015 and 2016 (2017 saw a slight decline), maintaining Germany’s place as Europe’s largest carbon emitter. Chancellor Angela Merkel has scrapped her pledge to slash carbon emissions to 40 percent of 1990 levels by the year 2020. Several members have threatened to resign from her policy commission on coal if the government allows utility company RWE to mine for lignite in Hambach Forest.

Only a few years ago, during the Paris climate talks, Germany led the EU in pushing for ambitious plans to curb emissions. Now, it seems to be having second thoughts. Recently, the European Union’s climate chief, Miguel Arias Cañete, suggested EU nations step up their commitment to reduce carbon emissions by 45 percent of 1990 levels instead of 40 percent by 2030. “I think we should first stick to the goals we have already set ourselves,” Merkel replied, even as a possible nuclear phaseout U-turn is debated, “I don’t think permanently setting ourselves new goals makes any sense.”

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Edmonton Electricity Rate Increase signals Alberta RRO changes as the UCP ends the NDP price cap; kilowatt-hour rises to 7.5 cents, raising energy bills for typical households by 3.9 percent in December.

Key Points

The end of Alberta’s RRO cap lifts kWh to 7.5 cents, raising an average Edmonton home’s bill about 3.9% in December.

✅ RRO price cap scrapped; kWh set at 7.5 cents in December.

✅ Average 600 kWh home pays about $7.37 more vs November.

✅ UCP ends NDP-era cap after stakeholder and consumer feedback.

Electricity will be more expensive for some Edmontonians in December after the UCP government scrapped a program that capped rates amid prices spiking in Alberta this year.

Effective Nov. 30, the province got rid of the consumer price cap program for Regulated Rate Option customers.

In 2017, the NDP government capped the kilowatt per hour price at 6.8 cents under a consumer price cap policy, meaning Edmontonians would pay the market rate and not more than the capped price.

In December, kWh will cost 7.5 cents amid expert warnings to lock in rates across Alberta. Typical Edmonton homes use an average of 600 kWh, increasing bills by $7.37, or 3.9 per cent, compared to November.

In Calgary, electricity bills have been rising as well, reflecting similar market pressures.

The NDP created the capacity system to bring price stability to Albertans, though a Calgary retailer urged scrapping the market overhaul at the time.

Energy Minister Sonya Savage said the UCP decided to scrap it after "overwhelming" feedback from consumers and industry stakeholders, as the province introduced new electricity rules earlier this year. 

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Canadian EV Manufacturing is accelerating with GM, Ford, and Project Arrow, integrating cross-border supply chains, battery production, rare-earths like lithium and cobalt, autonomous tech, and home charging to drive clean mobility and decarbonization.

Key Points

Canadian EV manufacturing spans electric and autonomous vehicles, domestic batteries, and integrated US-Canada trade.

✅ GM and Ford retool plants for EVs and autonomous production

✅ Project Arrow showcases Canadian zero-emission supply capabilities

✅ Lithium, cobalt, and battery hubs target cross-border resilience

The storied North American automotive industry, the ultimate showcase of Canada’s high-tensile trade ties with the United States and emerging Canada-U.S. collaboration on EVs momentum, is about to navigate a dramatic hairpin turn.

But as the Big Three veer into the all-electric, autonomous era, some Canadians want to seize the moment and take the wheel.

“There’s a long shadow between the promise and the execution, but all the pieces are there,” says Flavio Volpe, president of the Automotive Parts Manufacturers’ Association.

“We went from a marriage on the rocks to one that both partners are committed to. It could be the best second chapter ever.”

Volpe is referring specifically to GM, which announced late last month an ambitious plan to convert its entire portfolio of vehicles to an all-electric platform by 2035.

But that decision is just part of a cascading transformation across the industry, marking an EV inflection point with existential ramifications for one of the most tightly integrated cross-border manufacturing and supply-chain relationships in the world.

China is already working hard to become the “source of a new way” to power vehicles, President Joe Biden warned last week.

“We just have to step up.”

Canada has both the resources and expertise to do the same, says Volpe, whose ambitious Project Arrow concept — a homegrown zero-emissions vehicle named for the 1950s-era Avro interceptor jet — is designed to showcase exactly that, as recent EV assembly deals in Canada underscore.

“We’re going to prove to the market, we’re going to prove to the (manufacturers) around the planet, that everything that goes into your zero-emission vehicle can be made or sourced here in Canada,” he says.

“If somebody wants to bring what we did over the line and make 100,000 of them a year, I’ll hand it to them.”

GM earned the ire of Canadian auto workers in 2018 by announcing the closure of its assembly plant in Oshawa, Ont. It later resurrected the facility with a $170-million investment to retool it for autonomous vehicles.

“It was, ‘You closed Oshawa, how dare you?’ And I was one of the ‘How dare you’ people,” Volpe says.

“Well, now that they’ve reopened Oshawa, you sit there and you open your eyes to the commitment that General Motors made.”

Ford, too, has entered the fray, promising $1.8 billion to retool its sprawling landmark facility in Oakville, Ont., to build EVs.

It’s a leap of faith of sorts, considering what market experts say is ongoing consumer doubt about EVs and EV supply shortages that drive wait times.

“Range anxiety” — the persistent fear of a depleted battery at the side of the road — remains a major concern, even though it’s less of a problem than most people think.

Consulting firm Deloitte Canada, which has been tracking automotive consumer trends for more than a decade, found three-quarters of future EV buyers it surveyed planned to charge their vehicles at home overnight.

“The difference between what is a perceived issue in a consumer’s mind and what is an actual issue is actually quite negligible,” Ryan Robinson, Deloitte’s automotive research leader, says in an interview.

“It’s still an issue, full stop, and that’s something that the industry is going to have to contend with.”

So, too, is price, especially with the end of the COVID-19 pandemic still a long way off. Deloitte’s latest survey, released last month, found 45 per cent of future buyers in Canada hope to spend less than $35,000 — a tall order when most base electric-vehicle models hover between $40,000 and $45,000.

“You put all of that together and there’s still, despite the electric-car revolution hype, some major challenges that a lot of stakeholders that touch the automotive industry face,” Robinson says.

“It’s not just government, it’s not just automakers, but there are a variety of stakeholders that have a role to play in making sure that Canadians are ready to make the transition over to electric mobility.”

With protectionism no longer a dirty word in the United States and Biden promising to prioritize American workers and suppliers, the Canadian government’s job remains the same as it ever was: making sure the U.S. understands Canada’s mission-critical role in its own economic priorities.

“We’re both going to be better off on both sides of the border, as we have been in the past, if we orient ourselves toward this global competition as one force,” says Gerald Butts, vice-chairman of the political-risk consultancy Eurasia Group and a former principal secretary to Prime Minister Justin Trudeau.

“It served us extraordinarily well in the past … and I have no reason to believe it won’t serve us well in the future.”

Last month, GM announced a billion-dollar plan to build its new all-electric BrightDrop EV600 van in Ingersoll, Ont., at Canada’s first large-scale EV manufacturing plant for delivery vehicles.

That investment, Volpe says, assumes Canada will take the steps necessary to help build a homegrown battery industry — with projects such as a new Niagara-region battery plant pointing the way — drawing on the country’s rare-earth resources like lithium and cobalt that are waiting to be extracted in northern Ontario, Quebec and elsewhere.

Given that the EV industry is still in his infancy, the free market alone won’t be enough to ensure those resources can be extracted and developed, he says.

“General Motors made a billion-dollar bet on Canada because it’s going to assume that the Canadian government — this one or the next one — is going to commit” to building that business.

Such an investment would pay dividends well beyond the auto sector, considering the federal Liberal government’s commitment to lowering greenhouse gas-emissions, including a 2035 EV mandate, and meeting targets set out in the Paris climate accord.

“If you make investments in renewable energy and utility storage using battery technology, you can build an industry at scale that the auto industry can borrow,” Volpe says.

Major manufacturing, retail and office facilities would be able to use that technology to help “shave the peak” off Canada’s GHG emissions and achieve those targets, all the while paving the way for a self-sufficient electric-vehicle industry.

“You’d be investing in the exact same technology you’d use in a car.”

There’s one problem, says Robinson: the lithium-ion batteries on roads right now might not be where the industry ultimately lands.

“We’re not done with with battery technology,” Robinson says. “What you don’t want to do is invest in a technology that is that is rapidly evolving, and could potentially become obsolete going forward.”

Fuel cells — energy-efficient, hydrogen-powered units that work like batteries, but without the need for constant recharging — continue to be part of the conversation, he adds.

“The amount of investment is huge, and you want to be sure that you’re making the right decision, so you don’t find yourself behind the curve just as all that capacity is coming online.”

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Ontario Pumped Storage advances as Ontario's largest energy storage project, delivering clean electricity, long-duration capacity, and grid reliability for peak demand, led by TC Energy and Saugeen Ojibway Nation, with IESO review underway.

Key Points

A long-duration storage project in Meaford storing clean power for peak demand, supporting Ontario's emission-free grid.

✅ Stores clean electricity to power 1M homes for 11 hours

✅ Partnership: TC Energy and Saugeen Ojibway Nation

✅ Pending IESO review and OEB regulation decisions

In a bid to accelerate the province's ambitions for clean economic growth, TC Energy Corporation has announced significant progress in the development of the Ontario Pumped Storage Project. The Government of Ontario in Canada has unveiled a plan to address growing energy needs as a sustainable road map aimed at achieving an emission-free electricity sector, and as part of this plan, the Ministry of Energy is set to undertake a final evaluation of the proposed Ontario Pumped Storage Project. A decision is expected to be reached by the end of the year.

Ontario Pumped Storage is a collaborative effort between TC Energy and the Saugeen Ojibway Nation. The project is designed to be Ontario's largest energy storage initiative, capable of storing clean electricity to power one million homes for 11 hours. As the province strives to transition to a cleaner electricity grid by embracing clean power across sectors, long duration storage solutions like Ontario Pumped Storage will play a pivotal role in providing reliable, emission-free power during peak demand periods.

The success of the Project hinges on the approval of TC Energy's board of directors and a fruitful partnership agreement with the Saugeen Ojibway Nation. TC Energy is aiming for a final investment decision in 2024, as Ontario confronts an electricity shortfall in the coming years, with the anticipated in-service date being in the early 2030s, pending regulatory and corporate approvals.

“Ontario Pumped Storage will be a critical component of Ontario’s growing clean economy and will deliver significant benefits and savings to consumers,” said Corey Hessen, Executive Vice-President and President, TC Energy, Power and Energy Solutions. “Ontario continues to attract major investments that will have large power needs — many of which are seeking zero-emission energy before they invest. We are pleased the government is advancing efforts to recognize the significant role that long duration storage plays — firming resources, including new gas plants under provincial consideration, will become increasingly valuable in supporting a future emission-free electricity system.” 

The Municipality of Meaford also expressed its support for the project, recognizing the positive impact it could have on the local economy and the overall electricity system of Ontario. Additionally, various stakeholders, including LiUNA OPDC, LiUNA Local 183, and the Ontario Chamber of Commerce, lauded the potential for job creation, training opportunities, and resilient energy infrastructure as Ontario seeks new wind and solar power to ease a coming electricity supply crunch.

The timeline for Ontario Pumped Storage's progress includes a final analysis by the Independent Electricity System Operator (IESO) to confirm its role in Ontario's electricity system and in balancing demand and emissions during the transition, to be completed by 30 September 2023. Concurrently, the Ministry of Energy will engage in consultations on the potential regulation of the Project via the Ontario Energy Board, while debates over clean, affordable electricity intensify ahead of the Ontario election, with a final determination scheduled for 30 November 2023.

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