Exploring a smarter grid for Illinois

Negative Electricity Prices in France signal oversupply from wind and solar, stressing the wholesale market and grid. Better storage, demand response, and interconnections help balance renewables and stabilize prices today.

Key Points

They occur when renewable output exceeds demand, pushing power prices below zero as excess energy strains the grid.

✅ Driven by wind and solar surges with low demand

✅ Challenges thermal plants; erodes margins at negative prices

✅ Needs storage, demand response, and cross-border interties

France has recently experienced an unusual and unprecedented situation in its electricity market: negative electricity prices. This development, driven by a significant influx of renewable energy sources, highlights the evolving dynamics of energy markets as countries increasingly rely on clean energy technologies. The phenomenon of negative pricing reflects both the opportunities and renewable curtailment challenges associated with the integration of renewable energy into national grids.

Negative electricity prices occur when the supply of electricity exceeds demand to such an extent that producers are willing to pay consumers to take the excess energy off their hands. This situation typically arises during periods of high renewable energy generation coupled with low energy demand. In France, this has been driven primarily by a surge in wind and solar power production, which has overwhelmed the grid and created an oversupply of electricity.

The recent surge in renewable energy generation can be attributed to a combination of favorable weather conditions and increased capacity from new renewable energy installations. France has been investing heavily in wind and solar energy as part of its commitment to reducing greenhouse gas emissions and transitioning towards a more sustainable energy system, in line with renewables surpassing fossil fuels in Europe in recent years. While these investments are essential for achieving long-term climate goals, they have also led to challenges in managing energy supply and demand in the short term.

One of the key factors contributing to the negative prices is the variability of renewable energy sources. Wind and solar power are intermittent by nature, meaning their output can fluctuate significantly depending on weather conditions, with solar reshaping price patterns in Northern Europe as deployment grows. During times of high wind or intense sunshine, the electricity generated can far exceed the immediate demand, leading to an oversupply. When the grid is unable to store or export this excess energy, prices can drop below zero as producers seek to offload the surplus.

The impact of negative prices on the energy market is multifaceted. For consumers, negative prices can lead to lower energy costs as wholesale electricity prices fall during oversupply, and even potential credits or payments from energy providers. This can be a welcome relief for households and businesses facing high energy bills. However, negative prices can also create financial challenges for energy producers, particularly those relying on conventional power generation methods. Fossil fuel and nuclear power plants, which have higher operating costs, may struggle to compete when prices are negative, potentially affecting their profitability and operational stability.

The phenomenon also underscores the need for enhanced energy storage and grid management solutions. Excess energy generated from renewable sources needs to be stored or redirected to maintain grid stability and avoid negative pricing situations. Advances in battery storage technology, such as France's largest battery storage platform, and improvements in grid infrastructure are essential to addressing these challenges and optimizing the integration of renewable energy into the grid. By developing more efficient storage solutions and expanding grid capacity, France can better manage fluctuations in renewable energy production and reduce the likelihood of negative prices.

France's experience with negative electricity prices is part of a broader trend observed in other countries with high levels of renewable energy penetration. Similar situations have occurred in Germany, where solar plus storage is now cheaper than conventional power, the United States, and other regions where renewable energy capacity is rapidly expanding. These instances highlight the growing pains associated with transitioning to a cleaner energy system and the need for innovative solutions to balance supply and demand.

The French government and energy regulators are closely monitoring the situation and exploring measures to mitigate the impact of negative prices. Policy adjustments, market reforms, and investments in energy infrastructure are all potential strategies to address the challenges posed by high renewable energy generation. Additionally, encouraging the development of flexible demand response programs and enhancing grid interconnections with neighboring countries can help manage excess energy and stabilize prices.

In the long term, the rise of renewable energy and the occurrence of negative prices represent a positive development for the energy transition. They indicate progress towards cleaner energy sources and a more sustainable energy system. However, managing the associated challenges is crucial for ensuring that the transition is smooth and economically viable for all stakeholders involved.

In conclusion, the recent instance of negative electricity prices in France highlights the complexities of integrating renewable energy into the national grid. While the phenomenon reflects the success of France’s efforts to expand its renewable energy capacity, it also underscores the need for advanced grid management and storage solutions. As the country continues to navigate the transition to a more sustainable energy system, addressing these challenges will be essential for maintaining a stable and efficient energy market. The experience serves as a valuable lesson for other nations undergoing similar transitions and reinforces the importance of innovation and adaptability in the evolving energy landscape.

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PG&E Bankruptcy Plan outlines wildfire victims compensation via a $13.5B trust funded by cash and stock, aiming CPUC and court approval before June 30 to access the state wildfire insurance fund and finalize settlement.

Key Points

A regulator-approved plan funding a $13.5B wildfire victims trust with cash and PG&E stock to exit bankruptcy.

✅ $13.5B trust split between cash and PG&E shares

✅ Targets CPUC and court approval to meet June 30 deadline

✅ Accesses state wildfire insurance fund for future risks

Pacific Gas & Electric's plan for getting out of bankruptcy has won overwhelming support from the victims of deadly Northern California wildfires ignited by the utility's fraying electrical grid, while some have pursued mega-fire lawsuits through the courts as well, despite concerns that they will be shortchanged by a $13.5 billion fund that's supposed to cover their losses.

The company announced the preliminary results of the vote on Monday without providing a specific tally. Those numbers are supposed to be filed with U.S. Bankruptcy Judge Dennis Montali by Friday.

The backing of the wildfire victims keeps PG&E on track to meet a June 30 deadline to emerge from bankruptcy in time to qualify for a coverage from a California wildfire insurance fund created to help protect the utility from getting into financial trouble again.

The current bankruptcy case, which began early last year, will require PG&E to pay out about $25.5 billion to cover the devastation caused by its neglect, including a Camp Fire guilty plea that underscored liabilities in court proceedings. It's the second time in less than 20 years that PG&E has filed for bankruptcy.

The backing for PG&E's plan isn't a surprise, even though some of the roughly 80,000 wildfire victims had been trying to rally resistance to what they consider to be a deeply flawed plan. The misgivings mostly center on the massive debt that the utility will take on to finance the plan and uncertainties about the fluctuating value of the $6.75 billion in company stock that comprises half of the $13.5 billion promised them.

As it became apparent that the COVID-19 pandemic would drive the economy into a deep recession, PG&E's shares plunged along with the rest of the stock market during March, even as it announced pandemic response measures for customers and employees during that period. That led one financial expert to estimate the PG&E stock earmarked for the wildfire victims' trust would be worth only $4.85 billion, a nearly 30% markdown.

But PG&E's stock price has rebounded in recent weeks and it's now worth more than it was when the deal setting up the victims' trust was struck last December. The shares surged more than 8% to $12.28 in Monday's late afternoon trading. The stock stood at $9.65 when PG&E reached its settlement the wildfire victims.

Critics of the utility's plan also are upset because the company still hasn't specified when the fire victims will be able to sell the shares. It now seems likely the victims will have to hold the stock through the upcoming wildfire season in Northern California, raising the specter that another calamity caused by the utility's badly outdated equipment, as power line fire reports have underscored, could cause the shares to plummet before they can cash out.

A petition signed by more than 3,100 wildfire victims recently urged Gov. Gavin Newsom to consider pushing back the deadline for qualifying for the state's wildfire from June 30 to late August to allow for more time to revise PG&E's plan, as many also turn to a wildfire assistance program for interim aid while they wait. Newsom's office hasn't responded to inquiry about the plan from The Associated Press.

But the lawyers representing the wildfire victims advised their clients to vote in favor of PG&E's plan, contending that it's the best deal they are going to get.

PG&E still must get its plan approved by the judge supervising its case, and a recent judge order on dividend use underscores the focus on wildfire mitigation. The confirmation hearings are scheduled to begin May 27. The judge, though, has indicated he will give great weight to the wishes of the wildfire victims.

California state regulators also must approve PG&E's plan, amid projections that rates will stabilize in 2025 for customers. A vote on that is scheduled Thursday before the Public Utilities Commission.

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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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B.C. LNG Electrification embeds clean hydro and wind power into low-emission liquefied natural gas, cutting carbon intensity, enabling coal displacement in Asia, and opening grid-scale demand for independent power producers and ITMO-based climate accounting.

Key Points

Powering LNG with clean electricity cuts carbon intensity, displaces coal, and grows demand for B.C.'s clean power.

✅ Electric-drive LNG cuts emissions intensity by up to 80%.

✅ Creates major grid load, boosting B.C. independent power producers.

✅ Enables ITMO crediting when coal displacement is verified.

B.C. has abundant clean power – if only there was a way to ship those electrons across the sea to help coal-dependent countries reduce their emissions, and even regionally, Alberta–B.C. grid link benefits could help move surplus power domestically.

Natural gas that is liquefied using clean hydro and wind power and then exported would be, in a sense, a way of embedding B.C.’s low emission electricity in another form of energy, and, alongside the Canada–Germany clean energy pact, part of a broader export strategy.

Given the increased demand that could come from an LNG industry – especially one that moves towards greater electrification and, as the IEA net-zero electricity report notes, broader system demand – poses some potentially big opportunities for B.C.’s clean energy independent power sector, as those attending the Clean Energy Association of BC's annual at the Generate conference heard recently.

At a session on LNG electrification, delegates were told that LNG produced in B.C. with electricity could have some significant environmental benefits.

Given how much power an LNG plant that uses electric drive consumes, an electrified LNG industry could also pose some significant opportunities for independent power producers – a sector that had the wind taken out of its sails with the sanctioning of the Site C dam project.

Only one LNG plant being built in B.C. – Woodfibre LNG – will use electric drive to produce LNG, although the companies behind Kitimat LNG have changed their original design plans, and now plan to use electric drive drive as well.

Even small LNG plants that use electric drive require a lot of power.

“We’re talking about a lot of power, since it’s one of the biggest consumers you can connect to a grid,” said Sven Demmig, head of project development for Siemens.

Most LNG plants still burn natural gas to drive the liquefaction process – a choice that intersects with climate policy and electricity grids in Canada. They typically generate 0.35 tonnes of CO2e per tonne of LNG produced.

Because it will use electric drive, LNG produced by Woodfibre LNG will have an emissions intensity that is 80% less than LNG produced in the Gulf of Mexico, said Woodfibre president David Keane.

In B.C., the benchmark for GHG intensities for LNG plants has been set at 0.16 tonnes of CO2e per tonne of LNG. Above that, LNG producers would need to pay higher carbon taxes than those that are below the benchmark.

The LNG Canada plant has an intensity of 0.15 tonnes og CO2e per tonne of LNG. Woodfibre LNG will have an emissions intensity of just 0.059, thanks to electric drive.

“So we will be significantly less than any operating facility in the world,” Keane said.

Keane said Sinopec has recently estimated that it expects China’s demand for natural gas to grow by 82% by 2030.

“So China will, in fact, get its gas supply,” Keane said. “The question is: where will that supply come from?

“For every tonne of LNG that’s being produced today in the United States -- and tonne of LNG that we’re not producing in Canada -- we’re seeing about 10 million tonnes of carbon leakage every single year.”

The first Canadian company to produce LNG that ended up in China is FortisBC. Small independent operators have been buying LNG from FortisBC’s Tilbury Island plant and shipping to China in ISO containers on container ships.

David Bennett, director of communications for FortisBC, said those shipments are traced to industries in China that are, indeed, using LNG instead of coal power now.

“We know where those shipping containers are going,” he said. “They’re actually going to displace coal in factories in China.”

Verifying what the LNG is used for is important, if Canadian producers want to claim any kind of climate credit. LNG shipped to Japan or South Korea to displace nuclear power, for example, would actually result in a net increase in GHGs. But used to displace coal, the emissions reductions can be significant, since natural gas produces about half the CO2 that coal does.

The problem for LNG producers here is B.C.’s emissions reduction targets as they stand today. Even LNG produced with electricity will produce some GHGs. The fact that LNG that could dramatically reduce GHGs in other countries, if it displaces coal power, does not count in B.C.’s carbon accounting.

Under the Paris Agreement, countries agree to set their own reduction targets, and, for Canada, cleaning up Canada’s electricity remains critical to meeting climate pledges, but don’t typically get to claim any reductions that might result outside their own country.

Canada is exploring the use of Internationally Transferred Mitigation Outcomes (ITMO) under the Under the Paris Agreement to allow Canada to claim some of the GHG reductions that result in other countries, like China, through the export of Canadian LNG.

“For example, if I were producing 4 million tonnes of greenhouse gas emissions in B.C. and I was selling 100% of my LNG to China, and I can verify that they’re replacing coal…they would have a reduction of about 60 or million tonnes of greenhouse gas emissions,” Keane said.

“So if they’re buying 4 million tonnes of emissions from us, under these ITMOs, then they have net reduction of 56 million tonnes, we’d have a net increase of zero.”

But even if China and Canada agreed to such a trading arrangement, the United Nations still hasn’t decided just how the rules around ITMOs will work.

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Canada Clean Electricity drives a net-zero grid by 2035, scaling renewables like wind, solar, and hydro, with storage, smart grids, interprovincial transmission, and electrification of vehicles, buildings, and industry to cut emissions and costs.

Key Points

Canada Clean Electricity is a shift to a net-zero grid by 2035 using renewables, storage, and smart grids to decarbonize

✅ Doubles non-emitting generation for electrified transport and heating

✅ Expands wind, solar, hydro with storage and smart-grid balancing

✅ Builds interprovincial lines and faster permitting with Indigenous partners

By Merran Smith and Mark Zacharias

Canada is an electricity heavyweight. In addition to being the world’s sixth-largest electricity producer and third-largest electricity exporter in the global electricity market today, Canada can boast an electricity grid that is now 83 per cent emission-free, not to mention residential electricity rates that are the cheapest in the Group of Seven countries.

Indeed, on the face of it, the country’s clean electricity system appears poised for success. With an abundance of sunshine and blustery plains, Alberta and Saskatchewan, the Prairie provinces most often cited for wind and solar, have wind- and solar-power potential that rivals the best on the continent. Meanwhile, British Columbia, Manitoba, Quebec, and Newfoundland and Labrador have long excelled at generating low-cost hydro power.

So it would only be natural to assume that Canada, with this solid head start and its generous geography, is already positioned to provide enough affordable clean electricity to power our much-touted net-zero and economic ambitions.

But the reality is that Canada, like most countries, is not yet prepared for a world increasingly committed to carbon neutrality, in part because demand for solar electricity has lagged, even as overall momentum grows.

The federal government’s forthcoming Clean Electricity Standard – a policy promised by the governing Liberals during the most recent election campaign and restated for an international audience by Prime Minister Justin Trudeau at the United Nations’ COP26 climate summit – would require all electricity in the country to be net zero by 2035 nationwide, setting a new benchmark. But while that’s an encouraging start, it is by no means the end goal. Electrification – that is, hooking up our vehicles, heating systems and industry to a clean electricity grid – will require Canada to produce roughly twice as much non-emitting electricity as it does today in just under three decades.

This massive ramp-up in clean electricity will require significant investment from governments and utilities, along with their co-operation on measures and projects such as interprovincial power lines to build an electric, connected and clean system that can deliver benefits nationwide. It will require energy storage solutions, smart grids to balance supply and demand, and energy-efficient buildings and appliances to cut energy waste.

While Canada has mostly relied on large-scale hydroelectric and nuclear power in the past, newer sources of electricity such as solar, wind, geothermal, and biomass with carbon capture and storage will, in many cases, be the superior option going forward, thanks to the rapidly falling costs of such technology and shorter construction times. And yet Canada added less solar and wind generation in the past five years than all but three G20 countries – Indonesia, Russia and Saudi Arabia, with some experts calling it a solar power laggard in recent years. That will need to change, quickly.

In addition, Canada’s Constitution places electricity policy under provincial jurisdiction, which has produced a patchwork of electricity systems across the country that use different energy sources, regulatory models, and approaches to trade and collaboration. While this model has worked to date, given our low consumer rates and high power reliability, collaborative action and a cohesive vision will be needed – not just for a 100-per-cent clean grid by 2035, but for a net-zero-enabling one by 2050.

Right now, it takes too long to move a clean power project from the proposal stage to operation – and far too long if we hope to attain a clean grid by 2035 and a net-zero-enabling one by 2050. This means that federal, provincial, territorial and Indigenous governments must work with rural communities and industry stakeholders to accelerate the approvals, financing and construction of clean energy projects and provide investor certainty.

In doing so, Canada can set a course to carbon neutrality while driving job creation and economic competitiveness, a transition many analyses deem practical and profitable in the long run. Our closest trading partners and many of the world’s largest companies and investors are demanding cleaner goods. A clean grid underpins clean production, just as it underpins our climate goals.

The International Energy Agency estimates that, for the world to reach net zero by 2050, clean electricity generation worldwide must increase by more than 2.5 times between today and 2050. Countries are already plotting their energy pathways, and there is much to learn from each other.

Consider South Australia. The state currently gets 62 per cent of its electricity from wind and solar and, combined with grid-scale battery storage, has not lost a single hour of electricity in the past five years. South Australia expects 100 per cent of its electricity to come from renewable sources before 2030. An added bonus given today’s high energy prices: Annual household electricity costs have declined there by 303 Australian dollars ($276) since 2018.

The transition to clean energy is not about sacrificing our way of life – it’s about improving it. But we’ll need the power to make it happen. That work needs to start now.

Merran Smith is the executive director of Clean Energy Canada, a program at the Morris J. Wosk Centre for Dialogue at Simon Fraser University in Vancouver. Mark Zacharias is a special adviser at Clean Energy Canada and visiting professor at the Simon Fraser University School of Public Policy.

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Hydro One Power Restoration showcases outage recovery after a severe windstorm, with crews repairing downed power lines, broken poles and crossarms, partnering with utilities and contractors to boost grid resilience and promote emergency kit preparedness.

Key Points

A coordinated response by Hydro One and partners to repair storm damage, restore outages, strengthen grid resilience.

✅ Crews repaired downed lines, broken poles, and crossarms

✅ Partners and contractors aided rapid outage restoration

✅ Investments improve grid resilience and emergency readiness

Hydro One crews have restored power to more than 277,000 customers following back-to-back storms, with impacts felt in communities like Sudbury where local crews worked to reconnect service, including a damaging windstorm on that caused 57 broken poles, 27 broken crossarms, as well as downed power lines and fallen trees on lines. Hydro One crews restored power to more than 140,000 customers within 24 hours of Friday's windstorm, even as Toronto outages persisted for some customers elsewhere.

'We understand power outages bring life to a halt, which is why we are continuously improving our storm response, as employee COVID-19 support demonstrated, while making smart investments in a resilient, reliable and sustainable electricity system to energize life for families, businesses and communities for years to come,' said David Lebeter, Chief Operating Officer, Hydro One. 'We thank our customers for their patience as our crews worked tirelessly, alongside our utility partners and contractors, including Ontario crews in Florida, to restore power as quickly and as safely as possible.'

Hydro One thanks all of its utility partners and contractors who assisted with restoration efforts following the windstorm (alongside similar Quebec outages that highlighted the broader impact), including Durham High Voltage, EPCOR, ERTH Power, K-Line Construction Ltd., Lakeland Power Distribution Ltd., North Bay Hydro, Sproule Powerline Construction Ltd. and Valard Construction.

Hydro One encourages customers to restock their emergency kits following these storms, which utilities such as BC Hydro have also characterized as atypical, and to be aware of support programs like our pandemic relief fund that can help during difficult periods, to ensure they're prepared for an emergency or extended power outage.

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