Will your wind turbine work?

Lockdown Electricity Demand Trends reveal later mornings, weaker afternoons, and delayed peaks as WFH, streaming, and video conferencing reshape energy demand curves, grid forecasting, and residential electricity usage across Europe, New York, Tokyo, and Singapore.

Key Points

Shifts in power use during lockdowns: later ramps, weaker afternoons, and higher, delayed evening peaks.

✅ Morning ramp starts later; midday demand dips

✅ Evening peak shifts 1-2 hours; higher late-night usage

✅ WFH and streaming raise residential load; industrial demand falls

Life in lockdown means getting up late, staying up till midnight and slacking off in the afternoons.

That’s what power market data in Europe show in the places where restrictions on activity have led to a widespread shift in daily routines of hundreds of millions of people.

It’s a similar story wherever lockdowns bite. In New York City electricity use has fallen as much as 18% from normal times at 8am. Tokyo and three nearby prefectures had a 5% drop in power use during weekdays after Japan declared a state of emergency on April 7, according to Tesla Asia Pacific, an energy forecaster.

Italy’s experience shows the trend most clearly since the curbs started there on March 5, before any other European country. Data from the grid operator Terna SpA gives a taste of what other places are also now starting to report, with global daily demand dips observed in many markets as well.

1. People are sleeping later

With no commute to the office people can sleep longer. Normally, electricity demand began to pick up between 6 a.m. and 8 a.m. Now in Germany, it’s clear coffee machines don’t go on until between 8 a.m. and 9 a.m., said Simon Rathjen, founder of the trading company MFT Energy A/S.

Germany, France and Italy -- which between them make up almost two thirds of the euro-zone economy -- all have furlough measures that allow workers to receive a salary while temporarily suspended from their jobs. The U.K. also has a support package. Many of these workers will be getting up later.

"Now I have quite a relaxed start to the morning,” said David Freeman, an analyst in financial services from London. "I don’t get up until about half an hour before I need to start work.”

2. Less productive afternoons

There is a deeper dip in electricity use in the afternoons. Previously, power use rose between 2pm and 5pm. Now it dips as people head out for a walk or some air, according to UK demand data from National Grid Plc

It’s "as though we are living through a month of Sundays”, said Iain Staffell, senior lecturer in sustainable energy at Imperial College London.

3. Evenings in

From 6pm electricity use begins to rise steeply as people finish work and start chores. Restrictions like work and home schooling that prevent much daytime TV watching lifts in the early evening. This following chart for Germany shows the evening peak for power use coming during later hours.

The evening is when electricity use is highest, with most people confined to their homes. Netflix Inc reported a record 15.8 million paid subscribers – almost double the figure forecast by Wall Street analysts. Video-streaming services like Netflix and YouTube have found a captive audience. The new Disney+ service surpassed 50 million subscribers in just five months, a faster pace than predicted.

Internet traffic is skyrocketing, with a surge in bandwidth-intensive applications like streaming services and Zoom. This may mean that monthly broadband consumption of as much as 600 gigabytes, about 35% higher than before, according to Bloomberg Intelligence.

In Singapore, electricity use has dropped off significantly since the country’s "circuit-breaker” efforts to keep people at home began April 7. Electricity use has fallen and stayed low during the day. But late at night is a different story, as power demand fell sharply immediately after the lockdown began, it has steadily crept back in the past two weeks, perhaps a sign that Tiger King and The Last Dance have been finding late-night fans in the city state.

In Ottawa, COVID-19 closures made it seem as if the city had fallen off the electricity grid, according to local reports.

4. Staying up late

We’re going to bed later too. Demand doesn’t start to drop off until 10pm to 12am, at least an hour later than before.

"My children are definitely going to bed later,” said Liz Stevens, a teaching assistant from London. "Our whole routine is out the window.”

It’s challenging for those that need to predict behaviour – power grids and electricity traders. Forecasting is based on historical data, and there isn’t anything to go into the models gauging use now.

The closest we can get is looking at big events like football World Championships when people are all sitting down at the same time, according to Rathjen at MFT.

"Forecasting demand right now is very tricky,” said Chris Kimmett, director of power grids at Reactive Technologies Ltd. "A global pandemic is uncharted territory."

What normal looks like when the crisis passes is also an open question. Different countries are set to unravel their measures in their own ways, and global power demand has already surged above pre-pandemic levels in some analyses, with Germany and Austria loosening restrictions first and Italy remaining under tight control. Some changes may be permanent, with both workers and employers becoming more comfortable with working from home.

5. Different sectors consume more

In China, which is further along recovering from the pandemic than Europe or the US, the sharp contraction in overall power output masks a shift in daily routines.

Eating habits have changed. Restaurants are expanding delivery and even offering grocery services as the preference for dining at home persists. Household electricity consumption in China probably increased from activities such as cooking and heating, according to IHS Markit, which said that residential demand rose by 2.4% in the first two months as people stayed in.

The increase in technology use also drove China’s power demand from the telecom and web-service sectors to rise by 27%, the consultancy said.

Overall, China power demand in the first quarter of the year fell 6.5% from the same period in 2019 to 1.57 trillion kilowatt-hours, China’s National Energy Administration said last week. Industry uses about 70% of the country’s electricity, while the commercial sector and households account for 14% each. – Bloomberg

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UK Coal Phase-Out marks record-low coal generation as the UK grid shifts to renewable power, wind farms, and a net zero trajectory, slashing carbon emissions and supporting cleaner EV charging across the electricity system.

Key Points

UK Coal Phase-Out ends coal-fired electricity nationwide, powered by renewables and net zero policy to cut grid carbon.

✅ Coal's Q2 share fell to 0.7%, a record low

✅ Renewables up 12% with Beatrice wind farm

✅ EV charging grows cleaner as grid decarbonizes

The share of coal in the UK’s electricity system has fallen to record lows in recent months, alongside a coal-free power record, according to government data.

The figures show electricity generated by the UK’s most polluting power plants made up an average of 0.7% of the total in the second quarter of this year, a shift underway since wind first outpaced coal in 2016 across the UK. The amount of coal used to power the electricity grid fell by almost two-thirds compared with the same months last year.

A government spokesperson said coal-generated energy “will soon be a distant memory” as the UK moves towards becoming a net zero emissions economy, despite signs that low-carbon generation stalled in 2019 in some analyses.

“This new record low is a result of our world-leading low-carbon energy industry, which provided more than half of our energy last year and continues to go from strength to strength as we aim to end our contribution to climate change entirely by 2050,” the spokesperson said.

The UK electricity market is on track to end coal power after 142 years by the government’s target date of 2025.

This year three major energy companies have announced plans to close coal-fired power plants in the UK, which would leave only four remaining after the coming winter, ahead of the last coal power station going offline nationwide.

RWE said this month it would close the Aberthaw B power station in south Wales, its last UK coal plant, after the winter. SSE will close the Fiddler’s Ferry plant near Warrington, Cheshire, in March 2020, and EDF Energy will shutter the Cottam coal plant in September.

So far this year the UK has gone more than 3,000 hours without using coal for power, including a full week without coal earlier in the year – nearly five times more than the whole of 2017.

Meanwhile, the government’s data shows that renewable energy climbed by 12% from the second quarter of last year, boosted by the startup of the Beatrice windfarm in the Moray Firth in Scotland, and the UK leading the G20 in wind power share in recent assessments.

The cleaner power system could accelerate carbon savings from the UK’s roads, too, as more drivers opt for electric vehicles. A study by Imperial College London for the energy company Drax found that the UK’s increasingly low-carbon energy system meant electric cars were a greener option even when taking into account the carbon emissions produced by making car batteries.

Dr Iain Staffell, of Imperial College London, said: “An electric vehicle in the UK simply cannot be more polluting than its petrol or diesel equivalent – even when taking into account the upfront carbon cost of manufacturing their batteries. Any EV bought today could be emitting just a tenth of what a petrol car would in as little as five years’ time, as the electricity it uses to charge comes from an increasingly low-carbon mix.”

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

Key Points

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

✅ $5.6B yearly subsidy masks electricity rates and deficits

✅ Nuclear refurbishments embed rising costs for decades

✅ Efficiency, storage, and DERs stalled amid weak planning

By Mark Winfield

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Texas ERCOT Power Grid leads U.S. wind generation yet faces isolated interconnection, FERC exemption, and high industrial energy use, with distinct electricity and natural gas prices managed by a single balancing authority.

Key Points

The state-run interconnection that balances Texas electricity, isolated from FERC oversight and other U.S. grids.

✅ Largest U.S. wind power producer, high industrial demand

✅ Operates one balancing authority, independent interconnection

✅ Pays lower electricity, higher natural gas vs national average

For nearly two decades, the Lone Star State has generated more wind-sourced electricity than any other state in the U.S., according to the Energy Information Administration, or EIA.

In 2022, EIA reported Texas produced more electricity than any other state and generated twice as much as second-place Florida.

However, Texas also leads the country in another category. According to EIA, Texas is the largest energy-consuming state in the nation across all sectors with more than half of the state’s energy being used by the industrial sector.

As of May 2023, Texas residents paid 43% more for natural gas and around 10% less for electricity compared to the national average, according to EIA, and in competitive areas shopping for electricity is getting cheaper as well. Commercial and industrial sectors on average for the same month paid 25% less for electricity compared to the national average.

U.S. electric system compared to Texas
The U.S. electric system is essentially split into three regions called interconnections and are managed by a total of 74 entities called balancing authorities that ensure that power supply and demand are balanced throughout the region to prevent the possibility of blackouts, according to EIA.

The three regions (Interconnections):

Eastern Interconnection: Covers all U.S. states east of the Rocky Mountains, a portion of northern Texas, and consists of 36 balancing authorities.
Western Interconnection: Covers all U.S. states west of the Rockies and consists of 37 balancing authorities.
ERCOT: Covers the majority of Texas and consists of one balancing authority (itself).

During the 2021 winter storm, Texas electric cooperatives were credited with helping maintain service in many communities.

“ERCOT is unique in that the balancing authority, interconnection, and the regional transmission organization are all the same entity and physical system,” according to EIA, a structure often discussed in analyses of Texas power grid challenges today.

With this being the case, Texas is the only state in the U.S. that balances itself, the only state that is not subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC, and the only state that is not synchronously interconnected to the grid in the rest of the United States in the event of tight grid conditions, highlighting ongoing discussions about improving Texas grid reliability before peak seasons, according to EIA.

Every other state in the U.S. is connected to a web of multiple balancing authorities that contribute to ensuring power supply and demand are met.

California, for example, was the fourth largest electricity producer and the third largest electricity consumer in the nation in 2022, according to EIA, and California imports the most electricity from other states while Pennsylvania exports the most.

Although California produces significantly less electricity than Texas, it has the ability to connect with more than 10 neighboring balancing authorities within the Western Interconnection to interchange electricity, a dynamic that can see clean states importing dirty electricity under certain market conditions. ERCOT being independent only has electricity interchange with two balancing authorities, one of which is in Mexico.

Regardless of Texas’ unique power structure compared to the rest of the nation, the vast majority of the U.S. risked electricity supplies during this summer’s high heat, as outlined in severe heat blackout risks reports, according to EIA.

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ABO Wind Tunisia 10MW Solar Project will build a photovoltaic park in Gabes with a STEG PPA, fixed tariff, 2,500 m grid connection, producing 18 million kWh annually, targeted for 2020 commissioning with local partners.

Key Points

A 10MW photovoltaic park in Gabes with a 20-year STEG PPA and fixed tariff, slated for 2020 commissioning.

✅ 18 million kWh/year; 2,500 m grid tie, 20-year fixed tariff

✅ Electricity supplied to STEG under PPA; 2020 commissioning

✅ Located in Gabes; built with local partners, 10MW capacity

ABO Wind has received a permit and a tariff for a 10MW photovoltaic project in Tunisia, amid global activity such as Spain's 90MW wind project now underway, which it plans to build and commission in 2020.

The solar park, in the governorate of Gabes, is 400km south of the country’s capital Tunis and aligns with renewable funding initiatives seen across developing markets.

The developer said it plans to build the project next year in close cooperation with local partners, as regional markets from North Africa to the Gulf expand, with Saudi Arabia boosting wind capacity as well.

ABO Wind department head Nicolas Konig said: “The solar park will produce more than 18 million kilowatt hours of electricity per year and will feed it into the grid at a distance of 2500 metres.”

The developer will conclude an electricity supply contract with the state-owned energy supplier (Societe tunisienne de l’electricite et du gaz (STEG), which will provide a fixed remuneration over 20 years, a model echoed by Germany's wind-solar tender for the electricity fed into the grid.

Earlier this year, ABO Wind had already secured a tariff for a wind farm with a capacity of 30MW in a tender, 35km south-east of Tunis, underscoring Tunisia's wind investments under its long-term plan.

The company is working on half a dozen Tunisian wind and solar projects, as institutions like the World Bank support wind growth in developing countries.

“We are making good progress on our way to assemble a portfolio of several ready-to-build wind and solar projects attractive to investors, as Saudi clean energy targets continue to expand globally,” said ABO Wind general manager responsible for international business development Patrik Fischer.

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BMW Hydrogen Fuel Cell Strategy positions iX5 and eDrive for zero-emission mobility, leveraging fuel cells, fast refueling, and hydrogen infrastructure as an alternative to BEVs, diversifying drivetrains across premium segments globally, rapidly.

Key Points

BMW's plan to commercialize hydrogen fuel-cell drivetrains like iX5 eDrive for scalable, zero-emission mobility.

✅ Fuel cells enable fast refueling and long range with water vapor only.

✅ Reduces reliance on lithium and cobalt via recyclable materials.

✅ Targets premium SUV iX5; limited pilots before broader rollout.

BMW is hanging in there with hydrogen, a stance mirrored in power companies' hydrogen outlook today. That’s what Oliver Zipse, the chairperson of BMW, reiterated during an interview last week in Goodwood, England. 

“After the electric car, which has been going on for about 10 years and scaling up rapidly, the next trend will be hydrogen,” he says. “When it’s more scalable, hydrogen will be the hippest thing to drive.”

BMW has dabbled with the idea of using hydrogen for power for years, even though it is obscure and niche compared to the current enthusiasm surrounding vehicles powered by electricity. In 2005, BMW built 100 “Hydrogen 7” vehicles that used the fuel to power their V12 engines. It unveiled the fuel cell iX5 Hydrogen concept car at the International Motor Show Germany in 2021. 

In August, the company started producing fuel-cell systems for a production version of its hydrogen-powered iX5 sport-utility vehicle. Zipse indicated it would be sold in the United States within the next five years, although in a follow-up phone call a spokesperson declined to confirm that point. Bloomberg previously reported that BMW will start delivering fewer than 100 of the iX5 hydrogen vehicles to select partners in Europe, the U.S., and Asia, where Asia leads on hydrogen fuel cells today, from the end of this year.

All told, BMW will eventually offer five different drivetrains to help diversify alternative-fuel options within the group, as hybrids gain renewed momentum in the U.S., Zipse says.

“To say in the U.K. about 2030 or the U.K. and in Europe in 2035, there’s only one drivetrain, that is a dangerous thing,” he says. “For the customers, for the industry, for employment, for the climate, from every angle you look at, that is a dangerous path to go to.” 

Zipse’s hydrogen dreams could even extend to the group’s crown jewel, Rolls-Royce, which BMW has owned since 1998. The “magic carpet ride” driving style that has become Rolls-Royce’s signature selling point is flexible enough to be powered by alternatives to electricity, says Rolls-Royce CEO Torsten Müller-Ötvös. 

“To house, let’s say, fuel cell batteries: Why not? I would not rule that out,” Müller-Ötvös told reporters during a roundtable conversation in Goodwood on the eve of the debut of the company’s first-ever electric vehicle, Spectre. “There is a belief in the group that this is maybe the long-term future.”

Such a vehicle would contain a hydrogen fuel-cell drivetrain combined with BMW’s electric “eDrive” system. It works by converting hydrogen into electricity to reach an electrical output of up to 125 kW/170 horsepower and total system output of nearly 375hp, with water vapor as the only emission, according to the brand.

Hydrogen’s big advantage over electric power, as EVs versus fuel cells debates note, is that it can supply fuel cells stored in carbon-fiber-reinforced plastic tanks. “There will [soon] be markets where you must drive emission-free, but you do not have access to public charging infrastructure,” Zipse says. “You could argue, well you also don’t have access to hydrogen infrastructure, but this is very simple to do: It’s a tank which you put in there like an old [gas] tank, and you recharge it every six months or 12 months.”

Fuel cells at BMW would also help reduce its dependency on raw materials like lithium and cobalt, because the hydrogen-based system uses recyclable components made of aluminum, steel, and platinum. 

Zipse’s continued commitment to prioritizing hydrogen has become an increasingly outlier position in the automotive world. In the last five years, electric-only vehicles have become the dominant alternative fuel — as the age of electric cars dawns ahead of schedule — if not yet on the road, where fewer than 3% of new cars have plugs, at least at car shows and new-car launches.

Rivals Mercedes-Benz and Audi scrapped their own plans to develop fuel cell vehicles and instead have poured tens of billions of dollars into developing pure-electric vehicle, including Daimler's electrification plan initiatives. Porsche went public to finance its own electric aspirations. 

BMW will make half of all new-car sales electric by 2030 across the group, with many expecting most drivers to go electric within a decade, which includes MINI and Rolls-Royce. 
 

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