Feds to study using electricity to 'reduce or eliminate' fossil fuels

European Electricity Market Trends 2020 highlight decarbonisation, rising renewables, EV adoption, shifting energy mix, COVID-19 impacts, fuel switching, hydro, wind and solar growth, gas price dynamics, and wholesale electricity price increases.

Key Points

EU power in 2020 saw lower emissions, more renewables, EV growth, demand shifts, and higher wholesale prices.

✅ Power sector CO2 down 14% on higher renewables, lower coal

✅ Renewables 39% vs fossil 36%; hydro, wind, solar expanded

✅ EV share hit 17%; wholesale prices rose with gas, ETS costs

According to the Market Observatory for Energy DG Energy report, the COVID-19 pandemic and favorable weather conditions are the two key drivers of the trends experienced within the European electricity market in 2020. However, the two drivers were exceptional or seasonal.

The key trends within Europe’s electricity market include:

1. Decrease in power sector’s carbon emissions

As a result of the increase in renewables generation and decrease in fossil-fueled power generation in 2020, the power sector was able to reduce its carbon footprint by 14% in 2020. The decrease in the sector’s carbon footprint in 2020 is similar to trends witnessed in 2019 when fuel switching was the main factor behind the decarbonisation trend.

However, most of the drivers in 2020 were exceptional or seasonal (the pandemic, warm winter, high
hydro generation). However, the opposite is expected in 2021, with the first months of 2021 having relatively cold weather, lower wind speeds and higher gas prices, with stunted hydro and nuclear output also cited, developments which suggest that the carbon emissions and intensity of the power sector could rise.

The European Union is targeting to completely decarbonise its power sector by 2050 through the introduction of supporting policies such as the EU Emissions Trading Scheme, the Renewable Energy Directive and legislation addressing air pollutant emissions from industrial installations, with expectations that low-emissions sources will cover most demand growth in the coming years.

According to the European Environment Agency, Europe halved its power sector’s carbon emissions in 2019 from 1990 levels.

2. Changes in energy consumption

EU consumption of electricity fell by -4% as majority of industries did not operate at full level during the first half of 2020. Although majority of EU residents stayed at home, meaning an increase in residential energy use, rising demand by households could not reverse falls in other sectors of the economy.

However, as countries renewed COVID-19 restrictions, energy consumption during the 4th quarter was closer to the “normal levels” than in the first three quarters of 2020. 

The increase in energy consumption in the fourth quarter of 2020 was also partly due to colder temperatures compared to 2019 and signs of surging electricity demand in global markets.

3. Increase in demand for EVs

As the electrification of the transport system intensifies, the demand for electric vehicles increased in 2020 with almost half a million new registrations in the fourth quarter of 2020. This was the highest figure on record and translated into an unprecedented 17% market share, more than two times higher than in China and six times higher than in the United States.

However, the European Environment Agency (EEA)argues that the EV registrations were lower in 2020 compared to 2019. EEA states that in 2019, electric car registrations were close to 550 000 units, having reached 300 000 units in 2018.

4. Changes in the region’s energy mix and increase in renewable energy generation

The structure of the region’s energy mix changed in 2020, according to the report.

Owing to favorable weather conditions, hydro energy generation was very high and Europe was able to expand its portfolio of renewable energy generation such that renewables (39%) exceeded the share of fossil fuels (36%) for the first time ever in the EU energy mix.

Rising renewable generation was greatly assisted by 29 GW of wind and solar capacity additions in 2020, which is comparable to 2019 levels. Despite disrupting the supply chains of wind and solar resulting in project delays, the pandemic did not significantly slow down renewables’ expansion.

In fact, coal and lignite energy generation fell by 22% (-87 TWh) and nuclear output dropped by 11% (-79 TWh). On the other hand, gas energy generation was not significantly impacted owing to favorable prices which intensified coal-to-gas and lignite-to-gas switching, even as renewables crowd out gas in parts of the market.

5. Retirement of coal energy generation intensify

 As the outlook for emission-intensive technologies worsens and carbon prices rise, more and more early coal retirements have been announced. Utilities in Europe are expected to continue transitioning from coal energy generation under efforts to meet stringent carbon emissions reduction targets and as they try to prepare themselves for future business models that they anticipate to be entirely low-carbon reliant.

6. Increase in wholesale electricity prices

In recent months, more expensive emission allowances, along with rising gas prices, have driven up wholesale electricity prices on many European markets to levels last seen at the beginning of 2019. The effect was most pronounced in countries that are dependent on coal and lignite. The wholesale electricity prices dynamic is expected to filter through to retail prices.

The rapid sales growth in the EVs sector was accompanied by expanding charging infrastructure. The number of high-power charging points per 100 km of highways rose from 12 to 20 in 2020.

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EU Nuclear Power Dispute strains electricity market reform as Germany resists state aid for French reactors, while Eon urges cooperation to meet the energy transition, low-carbon goals, renewables integration, and cross-border power trade.

Key Points

A policy standoff between Germany and France over nuclear energy's role, state aid, and electricity market reforms.

✅ Germany opposes state aid for existing French nuclear plants.

✅ Eon CEO urges compromise to advance market reform and decarbonization.

✅ Cross-border trade shows reliance on French nuclear amid renewables push.

Germany should stop trying to impose its views on nuclear power on the rest of the EU, the head of one of Europe’s largest utilities has warned, as he stressed its importance in the region’s clean energy transition.

Leonhard Birnbaum, chief executive of German energy provider Eon, said Berlin should accept differences of opinion as he signalled his desire for a compromise with France to break a deadlock amid a nuclear power dispute over energy reforms.

Germany this year shut down its final three nuclear power plants as it followed through on a long-held promise to drop the use of the energy source, effectively turning its back on nuclear for now, while France has made it a priority to modernise its nuclear power plants.

The differences are delaying reforms to the region’s electricity market and legislation designed to meet greenhouse gas emissions targets.

One sticking point is Germany’s refusal to back French moves to allow governments to provide state aid to existing power plants, which could enable Paris to support the French nuclear fleet.

The Eon chief, whose company has 48mn customers across Europe, said it would be “better for everyone” if the two countries could approach the dispute with the mindset that “everyone does their part”, even as Germany has at times weighed a U-turn on the nuclear phaseout in recent debates.

“Neither the French will be able to persuade us to use nuclear power, nor we will be able to persuade them not to. That’s why I think we should take a different approach to the discussion,” he added.

Birnbaum said Germany “would do well to be a bit cautious about trying to impose our way on everyone else”. This approach was unlikely to be “crowned with success”.

“The better solution will not come from opposing each other, but from working together.”

Birnbaum made the comments at a press conference announcing Eon’s second-quarter results.

The company raised its profit outlook, predicting adjusted net income of €2.7bn to €2.9bn, and promised to reduce bills for customers as it hailed “diminishing headwinds” following the energy crisis caused by the war in Ukraine.

Birnbaum, whose company owned one of the three German nuclear plants shut down this year, pointed out that French nuclear energy was helping the conversion to a system of renewable energy in Germany at a time when Europe is losing nuclear power just when it needs energy.

This was a reference to Europe’s shared power market that allows countries to buy and sell electricity from one another. 

Germany has been a net importer of French electricity since shutting down its own nuclear plants, which last month prompted the French energy minister Agnès Pannier-Runacher to accuse Berlin of hypocrisy. 

“It’s a contradiction to massively import French nuclear energy while rejecting every piece of EU legislation that recognises the value of nuclear as a low-carbon energy source,” Pannier-Runacher told the German business daily Handelsblatt.

She also criticised Berlin’s drive to use new gas-fired power plants as a “bridge” to its target of being carbon neutral by 2045, even as some German officials contend that nuclear won’t solve the gas issue in the near term, arguing that it created a “credibility problem” for Germany: “Gas is a fossil fuel.”

Berlin officials responded by pointing out that Germany was a net exporter of electricity to France over the winter when its nuclear power stations were struggling to produce because of maintenance problems. 

They added that the country only imported French power because it was cheaper, not because their country was suffering shortages.

Berlin argues that renewable energy is cleaner and safer than nuclear, despite renewable rollout challenges linked to cheap Russian gas and grid expansion, and accuses France of seeking to protect the interests of its nuclear industry.

In Paris, officials see Germany’s resistance to nuclear energy as wrong-headed given the need to fight climate change effectively, and worry it is an attempt to undercut a key aspect of French industrial competitiveness.
 

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Demand Flexibility Service rewards households and businesses for shifting peak-time electricity use, enhancing grid balancing, energy security, and net zero goals with ESO and Ofgem support, virtual power plants, and 2GW capacity this winter.

Key Points

A grid program paying homes and businesses to shift peak demand, boosting energy security and lowering winter costs.

✅ Pays £3,000/MWh for reduced peak-time usage

✅ Targets at least 2GW via virtual power plants

✅ Rolled out by suppliers with Ofgem and ESO

This month we published our analysis of the British electricity system this winter. Our message is clear: in the base case our analysis indicates that supply margins are expected to be adequate, however this winter will undoubtedly be challenging, with high winter energy costs adding pressure. Therefore, all of us in the electricity system operator (ESO) are working round the clock to manage the system, ensure the flow of energy and do our bit to keep costs down for consumers.

One of the tools we have developed is the demand flexibility service, designed to complement efforts to end the link between gas and electricity prices and reduce bills. From November, this new capability will reward homes and businesses for shifting their electricity consumption at peak times. And we are working with the government, businesses and energy providers to encourage as high a level of take-up as possible. We are confident this innovative approach can provide at least 2 gigawatts of power – about a million homes’ worth.

What began as an initiative to help achieve net zero and keep costs down is also proving to be an important tool in ensuring Britain’s energy security, alongside the Energy Security Bill progressing into law.

We are particularly keen to get businesses involved right across Britain. When the Guardian first reported on this service we had calls from businesses ranging from multinationals to an owner of a fish and chip shop asking how they could do their bit and get signed up.

We can now confirm our proposals for how much people and businesses can be paid for shifting their electricity use outside peak times. We anticipate paying a rate of £3,000 per megawatt hour, reflecting the dynamics of UK natural gas and electricity markets today. Businesses and homes can become virtual power plants and, crucially, get paid like one too. For a consumer that could mean a typical household could save approximately £100, and industrial and commercial businesses with larger energy usage could save multiples of this.

We are working with Ofgem to get this scheme launched in November and for it to be rolled out through energy suppliers. If you are interested in participating, or understanding what you could get paid, please contact your energy supplier.

Innovations such as these have never mattered more. Vladimir Putin’s unlawful aggression means we are facing unprecedented energy market volatility, across the continent where Europe’s worst energy nightmare is becoming reality, and pressures on energy supplies this winter.

As a result of Russia’s war in Ukraine, European gas is scarce and prices are high, prompting Europe to weigh emergency measures to limit electricity prices amid the crisis. Alongside this, France’s nuclear fleet has experienced a higher number of outages than expected. Energy shortages in Europe could have knock-on implications for energy supply in Britain.

We have put in place additional contingency arrangements for this winter. For example, the ability to call on generators to fire-up emergency coal units, even as the crisis is a wake-up call to ditch fossil fuels for many, giving Britain 2GW of additional capacity.

We need to be clear, it is possible that without these measures supply could be interrupted for some customers for limited periods of time. This could eventually force us to initiate a temporary rota of planned electricity outages, meaning that some customers could be without power for up to three hours at a time through a process called the electricity supply emergency code (ESEC).

Under the ESEC process we would advise the public the day before any disconnections. We are working with government and industry on planning for this so that the message can be spread across all communities as quickly and accurately as possible. This would include press conferences, social media campaigns, and working with influencers in different communities.

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Toronto Grid Upgrade expands electricity capacity and reliability with new substations, upgraded transmission lines, and integrated renewable energy, supporting EV growth, sustainability goals, and resilient power for Toronto's growing residential and commercial sectors.

Key Points

A joint plan to boost grid capacity, add renewables, and improve reliability for Toronto's rising power demand.

✅ New substations and upgraded transmission lines increase capacity

✅ Integrates solar, wind, and storage for cleaner, reliable power

✅ Supports EV adoption, reduces outages, and future-proofs the grid

As Toronto's population and economy continue to expand, the surge in electricity demand in the city is also increasing rapidly. In response, the Ontario government, in partnership with the City of Toronto and various stakeholders, has launched an initiative to enhance the electricity infrastructure to meet future needs.

The Ontario Ministry of Energy and the City of Toronto are focusing on a multi-faceted approach that includes upgrades to existing power systems and the integration of renewable energy sources, as well as updated IoT cybersecurity standards for sector devices. This initiative is critical as Toronto looks towards a sustainable future, with projections indicating significant growth in both residential and commercial sectors.

Energy Minister Todd Smith highlighted the urgency of this project, stating, “With Toronto's growing population and dynamic economy, the need for reliable electricity cannot be overstated. We are committed to ensuring that our power systems are not only capable of meeting today's demands but are also future-proofed against the needs of tomorrow.”

The plan involves substantial investments in grid infrastructure to increase capacity and improve reliability. This includes the construction of new substations and the enhancement of old ones, along with the upgrading of transmission lines and exploration of macrogrids to strengthen reliability. These improvements are designed to reduce the frequency and severity of power outages while accommodating new developments and technologies such as electric vehicles, which are expected to place additional demands on the system.

Additionally, the Ontario government is exploring the potential for renewable energy sources, such as rooftop solar grids and wind, to be integrated into the city’s power grid. This shift towards green energy is part of a broader effort to reduce carbon emissions and promote environmental sustainability.

Toronto Mayor John Tory emphasized the collaborative nature of this initiative, stating, “This is a prime example of how collaboration between different levels of government and the private sector can lead to innovative solutions that benefit everyone. By enhancing our electricity infrastructure, we are not only improving the quality of life for our residents but also supporting Toronto's competitive edge as a global city.”

The project also includes a public engagement component, where citizens are encouraged to provide input on the planning and implementation phases. This participatory approach ensures that the solutions developed are in alignment with the needs and expectations of Toronto's diverse communities.

Experts agree that the timing of these upgrades is critical. As urban populations grow, the strain on infrastructure, especially in a powerhouse like Toronto, can lead to significant challenges. Proactive measures, such as those being implemented by Ontario and Toronto, and mirrored by British Columbia's clean energy shift underway on the west coast, are essential in avoiding potential crises and ensuring economic stability.

The success of this initiative could serve as a model for other cities facing similar challenges, highlighting the importance of forward-thinking and cooperation in urban planning and energy management. As Toronto moves forward with these ambitious plans, the eyes of the world, particularly other urban centers, will be watching and learning how to similarly tackle the dual challenges of growth and sustainability, with recent examples like London's newest electricity tunnel demonstrating large-scale grid upgrades.

This strategic approach to managing Toronto's electricity needs reflects a comprehensive understanding of the complexities involved in urban energy systems and a commitment to ensuring a resilient and sustainable future that aligns with Canada's net-zero grid by 2050 goals at the national level for all residents.

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California Governor Gavin Newsom vetoed a bill aimed at expanding load flexibility in state grid planning, citing conflicts with California’s resource adequacy framework and concerns over grid reliability and energy planning uncertainty.

Why has Newsom vetoed the Bill to Codify Load Flexibility?

Governor Gavin Newsom’s veto blocks legislation that would have required the California Energy Commission to incorporate load flexibility into the state’s energy planning and policy framework, a move that has stirred debate across the clean energy sector.

✅ Argues the bill conflicts with California’s existing Resource Adequacy system

✅ Draws backlash from clean energy and grid modernization advocates

✅ Exposes ongoing tension over how to manage renewable integration and demand response

California Governor Gavin Newsom has vetoed Assembly Bill 44, which would have required the California Energy Commission to evaluate and incorporate load management mechanisms into the state’s energy planning process. The move drew criticism from clean energy advocates who say it undermines efforts to strengthen grid reliability and reduce costs.

The bill directed the commission to adopt “upfront technical requirements and load modification protocols” that would allow load-serving entities to adjust their electrical demand forecasts. Proponents viewed this as a way to modernize California’s grid management, and to explore a revamp of electricity rates to help clean the grid, making it more responsive to demand fluctuations and renewable energy variability.

In his veto statement, Newsom said the bill was incompatible with existing energy planning frameworks, even as a looming electricity shortage remains a concern. “While I support expanding electric load flexibility, this bill does not align with the California Public Utility Commission’s Resource Adequacy framework,” he said. “As a result, the requirements of this bill would not improve electric grid reliability planning and could create uncertainty around energy resource planning and procurement processes.”

Newsom’s decision comes shortly after he signed a broad package of energy legislation that set the stage for a regional Western electricity market and extended the state’s cap-and-trade program. However, that legislative package did not include continued funding for several key grid reliability programs — including what advocates have called the world’s largest virtual power plant, a distributed network of connected devices that can balance electricity demand in real time.

Clean energy supporters saw AB 44 as a crucial step toward integrating these distributed energy resources into long-term grid planning. “With Assembly Bill 44 being vetoed, the state has missed a huge opportunity to advance common-sense policy that would have lowered costs, strengthened the grid, and unlocked the full potential of advanced energy,” said Edson Perez, California lead at Advanced Energy United.

Perez added that the setback increases pressure on lawmakers to take stronger action in the next legislative session. “The pressure is on next session to ensure that California is using all tools in its policy toolbox to build critically needed infrastructure, strengthen the grid, and bring costs down,” he said.

California’s growing use of demand response programs and virtual power plants has been central to its strategy for managing grid stress during heat waves and wildfire seasons. These systems allow utilities and customers to temporarily reduce or shift energy use, helping to prevent blackouts and reduce the need for fossil-fuel peaker plants during peak demand.

A recent report by the Brattle Group found that California’s taxpayer-funded virtual power plant could save ratepayers $206 million between 2025 and 2028 while reducing reliance on gas generation. The study, commissioned by Sunrun and Tesla Energy, highlighted the potential for flexible load management to improve both grid reliability and reduce costs, even as regulators weigh whether the state needs more power plants to ensure reliability.

Despite these findings, Newsom’s veto signals continued tension between state policymakers and clean energy advocates over how best to modernize California’s power grid. While the governor has prioritized large-scale renewable development and regional market integration, critics argue that California’s climate policy choices risk exacerbating reliability challenges and that failing to codify load flexibility could slow progress toward a more adaptive, resilient, and affordable clean energy future.

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Enbridge Alberta CCS Project targets carbon capture and storage in Alberta, capturing emissions from industrial emitters to advance net-zero goals, leveraging carbon pricing, regulatory support, and a hub model despite a key partner's exit.

Key Points

A proposed Alberta carbon capture hub by Enbridge to store industrial emissions and support net-zero targets.

✅ Seeks emitters across power, oil and gas, and heavy industry

✅ Backed by carbon pricing, regulation, and net-zero mandates

✅ Faces high capex, storage risk, and anchor-tenant uncertainty

Enbridge Inc., a Canadian energy giant, is digging its heels in on its proposed carbon capture and storage (CCS) project in Alberta. This comes despite the recent withdrawal of Capital Power, a major potential emitter that was expected to utilize the CCS technology. Enbridge maintains the project remains viable, but questions linger about its future viability without a cornerstone anchor.

The CCS project, envisioned as a major carbon capture hub in Alberta, aimed to capture emissions from industrial facilities and permanently store them underground. This technology has the potential to play a significant role in reducing greenhouse gas emissions and mitigating the effects of climate change, alongside grid solutions like bridging the Alberta-B.C. electricity gap that can complement decarbonization efforts.

Capital Power's decision to shelve its $2.4 billion Genesee Generating Station project, which was designed to integrate with the CCS hub, threw a wrench into Enbridge's plans. The Genesee project was expected to be a key source of emissions for capture and storage, and its status is being weighed as Ottawa advances the federal coal plan to phase out unabated coal.

Enbridge, however, remains optimistic. The company cites ongoing discussions with other potential emitters interested in utilizing the CCS technology, amid new funding signals such as the U.S. DOE's $110M for CCUS that highlight momentum. They believe the project holds significant value despite Capital Power's departure.

"We are confident in the long-term viability of the project and continue to actively engage with potential customers," said Enbridge spokesperson Rachel Giroux. "Carbon capture and storage is a critical technology for achieving net-zero emissions, and we believe there is a strong business case for our CCS project."

Enbridge's confidence hinges on several factors. Firstly, they believe there is a growing appetite for CCS technology amongst industrial facilities facing increasing pressure to reduce their carbon footprint. Regulations and carbon pricing mechanisms, including new U.S. EPA power plant rules that test CCS readiness, could further incentivize companies to adopt CCS solutions.

Secondly, Enbridge highlights the potential for capturing emissions from not just power plants but also from other industrial sectors like oil and gas production and clean hydrogen projects in Canada, where reforming processes can generate CO2. This broader application could significantly increase the captured carbon volume and strengthen the project's economic viability.

However, skepticism remains. Critics point to the high upfront costs associated with CCS development and the nascent stage of the technology. They argue that without a guaranteed stream of captured emissions, the project might not be financially sound. Additionally, the long-term safety and effectiveness of large-scale carbon storage solutions remain under scrutiny.

The success of Enbridge's CCS project hinges on attracting new emitters. Replacing Capital Power's contribution will be a significant challenge. Enbridge will need to demonstrate the project's economic viability and navigate the complex regulatory landscape surrounding CCS technology.

The Alberta government's position on CCS is crucial. While the government has expressed support for the technology, the level of financial and regulatory incentives offered will significantly impact investor confidence, especially as the IEA net-zero outlook underscores Canada's need for much more electricity. A clear and stable policy framework will be essential for attracting emitters to the project.

The future of Enbridge's CCS project remains uncertain. Capital Power's withdrawal is a setback, but Enbridge's continued commitment suggests they believe the technology holds promise. Whether they can find enough emitters to justify the project's development will be a critical test. The outcome will have significant implications for the future of CCS technology in Alberta and Canada's broader efforts to achieve net-zero emissions, including Canada-Germany clean energy cooperation that seeks to scale low-carbon fuels.

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