California Gets $500M to Upgrade Power Grid

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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Australia's greenhouse gas emissions rose in Q2 as electricity and transport pollution increased, despite renewable energy growth. Net zero targets, carbon dioxide equivalent metrics, and land use changes underscore mixed trends in decarbonisation.

Key Points

About 499-500 Mt CO2-e annually, with a 2% quarterly rise led by electricity and transport.

✅ Q2 emissions rose to 127 Mt from 124.4 Mt seasonally adjusted

✅ Electricity sector up to 41.6 Mt; transport added nearly 1 Mt

✅ Land use remains a net sink; renewables expanded capacity

Australia’s greenhouse gas emissions rose in the June quarter by about 2% as pollution from the electricity sector and transport increased.

Figures released on Tuesday by the Morrison government showed that on a year to year basis, emissions for the 12 months to last June totalled 498.9m tonnes of carbon dioxide equivalent. That tally was down 2.1%, or 10.8m tonnes compared with the same period a year earlier.

However, on a seasonally adjusted quarterly basis, emissions increased to 127m tonnes, or just over 2%, from the 124.4m tonnes reported in the March quarter. For the year to March, emissions totalled 494.2m tonnes, underscoring the pickup in pollution in the more recent quarter even as global coal power declines worldwide.

A stable pollution rate, if not a rising one, is also implied by the government’s release of preliminary figures for the September quarter. They point to 125m tonnes of emissions in trend terms for the July-September months, bringing the year to September total to about 500m tonnes, the latest report said.

The government has made much of Australia “meeting and beating” climate targets. However, the latest statistics show mostly emissions are not in decline despite its pledge ahead of the Glasgow climate summit that the country would hit net zero by 2050, and AEMO says supply can remain uninterrupted as coal phases out over the next three decades.

“Nothing’s happening except for the electricity sector,” said Hugh Saddler, an honorary associate professor at the Australian National University. Once Covid curbs on the economy eased, such as during the current quarter, emission sources such as from transport will show a rise, he predicted.

Falling costs for new wind and solar farms, with the IEA naming solar the cheapest in history worldwide, are pushing coal and gas out of electricity generation, as well as pushing down power prices. In seasonally adjusted terms, though, emissions for that sector rose from 39.7m tonnes the March quarter to 41.6m in the June one.

Most other sectors were steady, with pollution from transport adding almost 1m tonnes in the June quarter.

On an annual basis, a 500m tonnes tally is the lowest since records began in the 1990s, and IEA reported global emissions flatlined in 2019 for context. That lower trajectory, though, is lower due much to the land sector remaining a net sink even as some experts raise questions about the true trends when it comes to land clearing.

According to the government, this sector – known as land use, land-use change and forestry – amounted to a net reduction of emissions of 24.4m tonnes, or almost negative 5% of the national total, in the year to June.

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“The magnitude of this net sink has decreased by 0.6% (0.2 Mt CO2-e) on the previous 12 months due to an increase in emissions from agricultural soils, partially offset by a continuing decline in land clearing emissions,” the latest report said.

For its part, the government also touted the increase of renewable energy, as seen in Canada's electricity progress too, as central to driving emissions lower.

“Since 2017, Australia’s consumption of renewable energy has grown at a compound annual rate of 4.6%, with more than $40bn invested in Australia’s renewable energy sector,” Angus Taylor, the federal energy minister said, while UK net zero policy changes show a different approach. “Last year, Australia deployed new solar and wind at eight times the global per capita average.”

ANU’s Saddler said the main driver had been the 2020 Renewable Energy Target that the Coalition government had cut, and had anyway been implemented “a very considerable time ago”.

Tim Baxter, the Climate Council’s senior researcher, said “the time for leaning on the achievements of others is long since past”.

“We need a federal government willing to step up on emissions reductions and take charge with real policy, not wishlists,” he said, referring to the government’s net zero plan to rely on technologies to cut pollution in pursuit of a sustainable electric planet in practice, some of which don’t exist now.

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Germany Industrial Electricity Price Subsidy weighs subsidies for energy-intensive industries to bolster competitiveness as Germany shifts to renewables, expands grid capacity, and debates free-market tax cuts versus targeted relief and long-term policies.

Key Points

Policy to subsidize power for energy-intensive industry, preserving competitiveness during the energy transition.

✅ SPD backs 5-7 cents per kWh for 10-15 years

✅ FDP prefers tax cuts and free-market pricing

✅ Scholz urges cheap renewables and grid expansion first

Germany’s three-party coalition is debating whether electricity prices for energy-intensive industries should be subsidised in a market where rolling back European electricity prices can be tougher than it appears, to prevent companies from moving production abroad.

Calls to reduce the electricity bill for big industrial producers are being made by leading politicians, who, like others in Germany, fear the country could lose its position as an industrial powerhouse as it gradually shifts away from fossil fuel-based production, amid historic low energy demand and economic stagnation concerns.

“It is in the interest of all of us that this strong industry, which we undoubtedly have in Germany, is preserved,” Lars Klingbeil, head of Germany’s leading government party SPD (S&D), told Bayrischer Rundfunk on Wednesday.

To achieve this, Klingbeil is advocating a reduced electricity price for the industry of about 5 to 7 cents per Kilowatt hour, which the federal government would subsidise. This should be introduced within the next year and last for about 10 to 15 years, he said.

Under the current support scheme, which was financed as part of the €200 billion “rescue shield” against the energy crisis, energy-intensive industries already pay 13 cents per Kilowatt hour (KWh) for 70% of their previous electricity needs, which is substantially lower than the 30 to 40 cents per KWh that private consumers pay.

“We see that the Americans, for example, are spending $450 billion on the Inflation Reduction Act, and we see what China is doing in terms of economic policy,” Klingbeil said.

“If we find out in 10 years that we have let all the large industrial companies slip away because the investments are not being made here in Germany or Europe, and jobs and prosperity and growth are being lost here, then we will lose as a country,” he added.

However, not everyone in the German coalition favours subsidising electricity prices.

Finance Minister Christian Lindner of the liberal FDP (Renew), for example, has argued against such a step, instead promoting free-market principles and, amid rising household energy costs, reducing taxes on electricity for all.

“Privileging industrial companies would only be feasible at the expense of other electricity consumers and taxpayers, for example, private households or the small trade sector,” Lindner wrote in an op-ed for Handelsblatt on Tuesday.

“Increasing competitiveness for some would mean a loss of competitiveness for others,” he added.

Chancellor Olaf Scholz, himself a member of SPD, was more careful with his words, amid ongoing EU electricity reform debates in Brussels.

Asked about a subsidised electricity price for the industry at a town hall event on Monday, Scholz said he does not “want to make any promises now”.

“First of all, we have to make sure that we have cheap electricity in Germany in the first place,” Scholz said, promoting the expansion of renewable energy such as wind and solar, as local utilities cry for help, as well as more electricity grid infrastructure.

“What we will not be able to do as an economy, even as France’s new electricity pricing scheme advances, is to subsidise everything that takes place in normal economic activity,” Scholz said. “We should not get into the habit of doing that,” he added.

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Idaho Renewable Energy 2018 saw over 80% in-state utility-scale power from hydropower, wind, solar, biomass, and geothermal, per EIA, with imports declining as Snake River Plain resources and Hells Canyon hydro lead.

Key Points

Idaho produced over 80% in-state power from renewables in 2018, led by hydropower, wind, solar, and biomass.

✅ Hydropower supplies about half of capacity; Hells Canyon leads.

✅ Wind provides nearly 20% of capacity along the Snake River Plain.

✅ Utility-scale solar surged since 2016; biomass and geothermal add output.

More than 80% of Idaho’s in-state utility-scale electricity generation came from renewable resources in 2018, behind only Vermont, according to recently released data from the U.S. Energy Information Administration’s Electric Power Monthly and broader trends showing that solar and wind reached about 10% of U.S. generation in the first half of 2018.

Idaho generated 17.4 million MWh of electricity in 2018, of which 14.2 million MWh came from renewable sources, while nationally January power generation jumped 9.3% year over year according to EIA. Idaho uses a variety of renewable resources to generate electricity:

Hydroelectricity. Idaho ranked seventh in the U.S. in electricity generation from hydropower in 2018. About half of Idaho’s electricity generating capacity is at hydroelectric power plants, and utility actions such as the Idaho Power settlement could influence future resource choices, and seven of the state’s 10 largest power plants (in terms of electricity generation) are hydroelectric facilities. The largest privately owned hydroelectric generating facility in the U.S. is a three-dam complex on the Snake River in Hells Canyon, the deepest river gorge in North America.

Wind. Nearly one-fifth of Idaho’s electricity generating capacity and one-sixth of its generation comes from wind turbines. Idaho has substantial wind energy potential, and nationally the EIA expects solar and wind to be larger sources this summer, although only a small percentage of the state's land area is well-suited for wind development. All of the state’s wind farms are located in the southern half of the state along the Snake River Plain.

Solar. Almost 5% of Idaho’s electricity generating capacity and 3% of its generation come from utility-scale solar facilities, and nationally over half of new capacity in 2023 will be solar according to projections. The state had no utility-scale solar generation as recently as 2015. Between 2016 and 2017, Idaho’s utility-scale capacity doubled and generation increased from 30,000 MWh to more than 450,000 MWh. Idaho’s small-scale solar capacity also doubled since 2017, generating 33,000 MWh in 2018.

Biomass. Biomass-fueled power plants account for about 2% of the state’s utility-scale electricity generating capacity and 3% of its generation, contributing to a broader U.S. shift where 40% of electricity came from non-fossil sources in 2021. Wood waste from the state’s forests is the primary fuel for these plants.

Geothermal. Idaho is one of seven states with utility-scale geothermal electricity generation. Idaho has one 18-MW geothermal facility, located near the state’s southern border with Utah.

EIA says Idaho requires significant electricity imports, totaling about one-third of demand, to meet its electricity needs. However, Idaho’s electricity imports have decreased over time, and Georgia's recent import levels illustrate how regional dynamics can vary. Almost all of these imports are from neighboring states, as electricity imports from Canada accounted for less than 0.1% of Idaho’s total electricity supply in 2017.

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California income-based utility charges face bipartisan pushback as the PUC weighs fixed fees for PG&E, SDG&E, and Southern California Edison, reshaping rate design, electricity affordability, energy equity, and privacy amid proposed per-kWh reductions.

Key Points

PUC-approved fixed fees tied to household income for PG&E, SDG&E, and SCE, offset by lower per-kWh rates.

✅ Proposed fixed fees: $51 SCE, $73.31 SDG&E, $50.92 PG&E

✅ Critics warn admin, privacy, legal risks and higher bills for savers

✅ Backers say lower-income pay less; kWh rates cut ~33% in PG&E area

Efforts are being made across California's political landscape to derail a legislative initiative that introduced income-based utility charges for customers of Southern California Edison and other major utilities.

Legislators from both the Democratic and Republican parties have proposed bills aimed at nullifying the 2022 legislation that established a sliding scale for utility charges based on customer income, a decision made in a late-hour session and subsequently endorsed by Governor Gavin Newsom.

The plan, pending final approval from the state Public Utilities Commission (PUC) — all of whose current members were appointed by Governor Newsom — would enable utilities like Southern California Edison, San Diego Gas & Electric, and PG&E to apply new income-based charges as early as this July.

Among the state legislators pushing back against the income-based charge scheme are Democrats Jacqui Irwin and Marc Berman, along with Republicans Janet Nguyen, Kelly Seyarto, Rosilicie Ochoa Bogh, Scott Wilk, Brian Dahle, Shannon Grove, and Roger Niello.

A cadre of specialists, including economist Ahmad Faruqui who has advised all three utilities implicated in the fee proposal, have outlined several concerns regarding the PUC's pending decision.

Faruqui and his colleagues argue that the proposed charges are excessively high in comparison to national standards, reflecting soaring electricity prices across the state, potentially leading to administrative challenges, legal disputes, and negative unintended outcomes, such as penalizing energy-conservative consumers.

Advocates for the income-based fee model, including The Utility Reform Network (TURN) and the National Resources Defense Council, argue it would result in higher charges for wealthier consumers and reduced fees for those with lower incomes. They also believe that the utilities plan to decrease per kilowatt-hour rates as part of a broader rate structure review to balance out the new fees.

However, even supporters like TURN and the Natural Resources Defense Council acknowledge that the income-based fee model is not a comprehensive solution to making soaring electricity bills more affordable.

If implemented, California would have the highest income-based utility fees in the country, with averages far surpassing the national average of $11.15, as reported by EQ Research:

• Southern California Edison would charge $51.
• San Diego Gas & Electric would levy $73.31.
• PG&E would set fees at $50.92.

The proposal has raised concerns among state legislators about the additional financial burden on Californians already struggling with high electricity costs.

Critics highlight several practical challenges, including the PUC's task of assessing customers' income levels, a process fraught with privacy concerns, potential errors, and constitutional questions regarding access to tax information.

Economists have pointed out further complications, such as the difficulty in accurately assessing incomes for out-of-state property owners and the variability of customers' incomes over time.

The proposed income-based charges would differ by income bracket within the PG&E service area, for example, with lower-income households facing lower fixed charges and higher-income households facing higher charges, alongside a proposed 33% reduction in electricity rates to help mitigate the fixed charge impact.

Yet, the economists warn that most customers, particularly low-usage customers, could end up paying more, essentially rewarding higher consumption and penalizing efficiency.

This legislative approach, they caution, could inadvertently increase costs for moderate users across all income brackets, a sign of major changes to electric bills that could emerge, challenging the very goals it aims to achieve by promoting energy inefficiency.

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Europe 2023 Energy Shortfall underscores how weak hydro and nuclear offset record solar and wind, tightening grids as natural gas supplies shrink and demand rebounds, heightening risks of electricity shortages across key economies.

Key Points

A regional gap as weak hydro and nuclear offset record solar and wind, straining supply as gas stays tight.

✅ Hydro and nuclear output fell sharply in early 2023

✅ Record solar and wind could not offset the deficit

✅ Industrial demand rebound pressures limited gas supplies

Shortfalls in Europe's hydro and nuclear output have more than offset record electricity generation from wind and solar power sites over the first quarter of 2023, leaving the region vulnerable to acute energy shortages for the second straight year.

European countries fast-tracked renewable energy capacity development in 2022 in the wake of Russia's invasion of Ukraine last February, which upended natural gas flows to the region and sent power prices soaring.

Europe lifted renewable energy supply capacity by a record 57,290 megawatts in 2022, or by nearly 9%, according to the International Energy Agency (IRENA), amid a scramble to replace imported Russian gas with cleaner, home-grown energy.

However, steep drops in both hydro and nuclear output - two key sources of non-emitting energy - mean Europe's power producers have limited ways to lift overall electricity generation, as the region is losing nuclear power at a critical moment, just as the region's economies start to reboot after last year's energy shock.

POWER PLATEAU
Europe's total electricity generation over the first quarter of 2023 hit 1,213 terawatt hours, or roughly 6.4% less than during the same period in 2022, according to data from think tank Ember.

At the same time, European power hits records during extreme heat as plants struggle to cool, exacerbating supply risks.

As Europe's total electricity demand levels were in post-COVID-19 expansion mode in early 2022 before Russia's so-called special operation sent power costs to record highs amid debates over how electricity is priced in Europe, it makes sense that overall electricity use was comparatively stunted in early 2023.

However, efforts are now underway to revive activity at scores of European factories, industrial plants and production lines that were shuttered or curtailed in 2022, so Europe's collective electricity consumption totals are set to trend steadily higher over the remainder of 2023.

With Russian natural gas unavailable in the previous quantities due to sanctions and supply issues, Europe's power producers will need to deploy alternative energy sources, including renewables poised to eclipse coal globally, to feed that increase in power demand.

And following the large jump in renewable capacity brought online in 2022, utilities can deploy more low-emissions energy than ever before across Europe's electricity grids.

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