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European Power Demand During Second Lockdowns remains resilient as winter heating offsets commercial losses; electricity consumption tracks seasonal norms, with weather sensitivity, industrial activity, natural gas shielding, and coal decline shaping dynamics under COVID-19 restrictions.

Key Points

It is expected to remain near seasonal norms, driven by heating, industry activity, and weather sensitive consumption.

✅ Winter heating offsets retail and hospitality closures

✅ Demand sensitivity rises with colder weather in France

✅ Gas generation shielded; coal likely to curtail first

European power demand is likely to hold up in the second round of national lockdown restrictions, with fluctuations most likely driven by changes in the weather.

Traders and analysts expect normal consumption this time around as home heating during the chilly season replaces commercial demand.

Last week electricity consumption in France, Germany and the U.K. was close to business-as-usual levels for the time of year, according to BloombergNEF data. By contrast, power demand had dropped 16% in the first seven days of the springtime lockdown, as reflected by the U.K.’s 10% daily decline reported then.

How power demand performs has significance outside the sector. It’s often seen as a proxy for economic growth and during lockdowns earlier this year, electricity use slumped along with GDP, and stunted hydro and nuclear output could further hobble recovery. For Western Europe, annual demand is expected to be 5% lower than the previous year, a bigger decline than after the global financial crisis in 2008, according to S&P Global Platts.

The Covid-19 limits are lighter than those from earlier in the year “with an explicit drive to preserve economic activity, particularly at the more energy-intensive industrial end of the spectrum,” said Glenn Rickson, head of European power analysis at S&P Global Platts.

Higher levels of working from home will offset some of the losses from shop and hospitality closures, “but also increase the temperature sensitivity of overall gas and power demand, as heat-driven demand records have shown in recent summers,” he said.

The latest wave of national lockdowns began in France, Germany, Spain, Italy and Britain, with Spain having seen April demand plummet earlier in the year, as coronavirus cases surged and officials struggled to keep the spread of the virus under control.

Much of the manufacturing industry remains working for now despite additional restrictions to contain the coronavirus. With the peak of the second wave yet to be reached, “it seems almost inevitable that the fourth quarter will prove economically challenging,” analysts at Alfa Energy said.

There will initially be significantly less of an impact on demand compared with this spring when global daily demand dipped about 15% and electricity consumption in Europe was down 30%, Johan Sigvardsson, power price analyst at Swedish utility Bixia AB said.

The prevalence of electric heating systems in France means that power demand is particularly sensitive to cold weather. A cold spell would significantly boost demand and drive record electricity prices in tight markets.

Similar to the last round of shutdowns, it’s use of coal that will probably be hit first if power demand sags, as transition-focused responses gather pace, leaving natural gas mostly shielded from fluctuations in the market.

“We expect that another drop in power demand would again impact coal-fired generation and shield gas power to some extent,” said Carlos Torres Diaz, an analyst at Rystad Energy.

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Hydro One Avista merger faces regulatory scrutiny in Washington, Oregon, and Idaho, as political risk outweighs defensive utilities fundamentals like stable cash flow, rate base growth, EPS outlook, and a near 5% dividend yield.

Key Points

A planned Hydro One-Avista acquisition awaiting key state approvals amid elevated political and regulatory risk.

✅ Hold rating, $24 price target, 28.1% implied return

✅ EPS forecast: $1.27 in 2018; $1.38 in 2019

✅ Defensive utility: stable cash flow, 4-6% rate base growth

A seemingly positive development for Hydro One is overshadowed by ongoing political and regulatory risk, as seen after the CEO and board ouster, Industrial Alliance Securities analyst Jeremy Rosenfield says.

On October 4, staff from the Washington Utilities and Transportation Commission filed updated testimony in support of the merger of Hydro One and natural gas distributor Avista, which had previously received U.S. antitrust clearance from federal authorities.

The merger, which was announced in July of 2017 has received the green light from federal and key states, with Washington, Oregon and Idaho being exceptions, though the companies would later seek reconsideration from U.S. regulators in the process.

But Rosenfield says even though decisions from Oregon and Idaho are expected by December, there are still too many unknowns about Hydro One to recommend investors jump into the stock.

Hydro One stock defensive but risky

“We continue to view Hydro One as a fundamentally defensive investment, underpinned by (1) stable earnings and cash flows from its regulated utility businesses (2) healthy organic rate base and earning growth (4-6%/year through 2022) and (3) an attractive dividend (~5% yield, 70-80% target payout),” the analyst says. “In the meantime, and ahead of key regulatory approvals in the AVA transaction, we continue to see heightened political/regulatory risk as an overhand on the stock, outweighing Hydro One’s fundamentals in the near term.”

In a research update to clients today, Rosenfield maintained his “Hold” rating and one year price target of $24.00 on Hydro One, implying a return of 28.1 per cent at the time of publication.

Rosenfield thinks Hydro One will generate EPS of $1.27 per share in fiscal 2018, even though its Q2 profit plunged 23% as electricity revenue fell. He expects that number will improve to EPS of $1.38 a share the following year.

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U.S. Utility-Scale Solar Delays driven by the coronavirus pandemic threaten construction timelines, supply chains, and financing, with interconnection and commissioning setbacks, module sourcing risks in Southeast Asia, and tax credit deadline pressures impacting project delivery.

Key Points

Setbacks to large U.S. solar builds from COVID-19 impacting construction, supply, financing, and permitting.

✅ Construction, interconnection, commissioning site visits delayed

✅ Supply chain risks for modules from Southeast Asia

✅ Tax credit deadline extensions sought by developers

About 5 gigawatts (GW) of big U.S. solar energy projects, enough to power nearly 1 million homes, could suffer delays this year if construction is halted for months due to the coronavirus pandemic, as the Covid-19 crisis hits renewables across the sector, according to a report published on Wednesday.

The forecast, a worst-case scenario laid out in an analysis by energy research firm Wood Mackenzie, would amount to about a third of the utility-scale solar capacity expected to be installed in the United States this year, even as US solar and wind growth continues under favorable plans.

The report comes two weeks after the head of the top U.S. solar trade group called the coronavirus pandemic (as solar jobs decline nationwide) "a crisis here" for the industry. Solar and wind companies are pleading with Congress to extend deadlines for projects to qualify for sunsetting federal tax credits.

Even the firm’s best-case scenario would result in substantial delays, mirroring concerns that wind investments at risk across the industry. With up to four weeks of disruption, the outbreak will push out 2 GW of projects, or enough to power about 380,000 homes. Before factoring in the impact of the coronavirus, Wood Mackenzie had forecast 14.7 GW of utility-scale solar projects would be installed this year.

In its report, the firm said the projects are unlikely to be canceled outright. Rather, they will be pushed into the second half of 2020 or 2021. The analysis assumes that virus-related disruptions subside by the end of the third quarter.

Mid-stage projects that still have to secure financing and receive supplies are at the highest risk, Wood Mackenzie analyst Colin Smith said in an interview, adding that it was too soon to know whether the pandemic would end up altering long-term electricity demand and therefore utility procurement plans, where policy shifts such as an ITC extension could reshape priorities.

Currently, restricted travel is the most likely cause of project delays, the report said. Developers expect delays in physical site visits for interconnection and commissioning, and workers have had difficulty reaching remote construction sites.

For earlier-stage projects, municipal offices that process permits are closed and in-person meetings between developers and landowners or local officials have slowed down.

Most solar construction is proceeding despite stay at home orders in many states because it is considered critical infrastructure, and long-term proposals like a tenfold increase in solar could reshape the outlook, the report said, adding that “that could change with time.”

Risks to supplies of solar modules include potential manufacturing shutdowns in key producing nations in Southeast Asia such as Malaysia, Vietnam and Thailand. Thus far, solar module production has been identified as an essential business and has been allowed to continue.

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Scotland Wind Energy October saw renewables supply the equivalent of 98 percent of electricity demand, as onshore wind outpaced National Grid needs, cutting emissions and powering households, per WWF Scotland and WeatherEnergy.

Key Points

A monthly update showing Scottish onshore wind met the equivalent of 98% of electricity demand in October.

✅ 98% of monthly electricity demand equivalent met by wind

✅ 16 days exceeded total national demand, per data

✅ WWF Scotland and WeatherEnergy cited; lower emissions

New figures publicized by WWF Scotland have revealed that wind energy generated the equivalent of 98% of the country’s electricity demand in October, or enough electricity to power millions of Scottish homes across the country.

Scotland has regularly been highlighted as a global wind energy leader, and over the last few years has repeatedly reported record-breaking months for wind generation. Now, it’s all very well and good to say that Scottish wind delivered 98% of the country’s electricity demand, but the specifics are a little different — hence why WWF Scotland always refers to it as wind providing “the equivalent of 98%” of Scotland’s electricity demand. That’s why it’s worth looking at the statistics provided by WWF Scotland, sourced from WeatherEnergy, part of the European EnergizAIR project:

• National Grid demand for the month – 1,850,512 MWh
• What % of this could have been provided by wind power across Scotland – 98%
• Best day – 23rd October 2018, generation was 105,900.94 MWh, powering 8.72m homes, 356% of households. Demand that day was 45,274.5MWh – wind generation was 234% of that.
• Worst day – 18th October 2018 when generation was 18,377.71MWh powering 1,512,568 homes, 62% of households. Demand that day was 73,628.5MWh – wind generation was 25%
• How many days generation was over 100% of households – 27
• How many days generation was over 100% of demand – 16

“What a month October proved to be, with wind powering on average 98 per cent of Scotland’s entire electricity demand for the month, at a time when wind became the UK’s main power source and exceeding our total demand for a staggering 16 out of 31 days,” said Dr Sam Gardner, acting director at WWF Scotland.

“These figures clearly show wind is working, it’s helping reduce our emissions and is the lowest cost form of new power generation. It’s also popular, with a recent survey also showing more and more people support turbines in rural areas. That’s why it’s essential that the UK Government unlocks market access for onshore wind at a time when we need to be scaling up electrification of heat and transport.”

Alex Wilcox Brooke, Weather Energy Project Manager at Severn Wye Energy Agency, added: “Octobers figures are a prime example of how reliable & consistent wind production can be, with production on 16 days outstripping national demand.”

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Community Solar for Low-Income Homes expands energy equity by delivering renewable energy access, predictable bill savings, and tax credit benefits to renters and energy-insecure households, accelerating distributed generation and storage adoption nationwide.

Key Points

A program model enabling renters and LMI households to subscribe to off-site solar and save on utility bills.

✅ Earn bill credits from shared solar generation.

✅ Expands access for renters and LMI subscribers.

✅ Often paired with storage and IRA tax credit adders.

On a square-foot basis, the issue of inequality is made worse by higher costs for energy usage in the nation. Efforts like community solar programs such as Maryland community solar are underway to boost low-income participation in the cost benefits of renewable energy.

The Energy Information Administration (EIA) shows that households that are considered energy insecure, or those that have the inability to adequately meet basic household energy costs, are paying more for electricity than their wealthier counterparts. 

On average in the United States in 2020, households were billed about $1.04 per square foot for all energy sources. For homes that did not report energy insecurity, that average was $0.98 per square foot, while homes with energy insecurity issues paid an average of $1.24 per square foot for energy. This means that U.S. residents that need the most support on their energy bills are stuck with costs 27% higher than their neighbors on square-foot-basis.

EIA said energy-insecure households have reduced or forgone basic necessities to pay energy bills, kept their houses at unsafe temperatures because of energy cost concerns, or been unable to repair heating or cooling equipment because of cost.

In 2020, households with income less than $10,000 a year were billed an average of $1.31 per square foot for energy, while households making $100,000 or more were billed an average of $0.96 per square foot, said EIA. Renters paid considerably more ($1.28 per square foot) than owners ($0.98 per square foot). There were also considerable differences between regions, with New England solar growth sparking grid upgrade debates, ethnic groups and races, and insulation levels, as seen below.

The energy transition toward renewables like solar has offered price stability, amid record solar and storage growth nationwide, but thus far energy-insecure communities have relatively been left behind. A recent Berkeley Lab report, Residential Solar-Adopter Income and Demographic Trends, indicates that even though the rate of solar adoption among low-income residents is increasing (from 5% in 2010 to 11% in 2021), that segment of energy consumers remains under-represented among solar adopters, relative to its share of the population.

Community solar efforts

As such, the United States is targeting communities most impacted by energy costs that have not benefitted from the transition, highlighting “Energy Communities” that are eligible for an additional 10% tax credit through funds made possible by the Inflation Reduction Act.

Additionally, a push for community solar development is taking place nationwide to extend access to affordable solar energy to renters and other residents that aren’t able to leverage finances to invest in predictable, low-cost residential solar systems. The Biden Administration set a goal this year to sign up 5 million community solar households, achieving $1 billion in bill savings by 2025. The community solar model only represents about 8% of the total distributed solar capacity in the nation. This target would entail a jump from 3 GW installed capacity to 20 GW by the target year. The Department of Energy estimates community solar subscribers save an average of 20% on their bills.

California this year passed AB 2316, the Community Renewable Energy Act takes aim at four acute problems in the state’s power market: reliability amid rising outage risks, rates, climate and equity. The law creates a community renewable energy program, including community solar-plus-storage, supported by cheaper batteries, to overcome access barriers for nearly half of Californians who rent or have low incomes. Community solar typically involves customers subscribing to an off-site solar facility, receiving a utility bill credit for the power it generates.

“Community renewable energy is a proven powerful tool to help close California’s clean energy gap, bringing much needed relief to millions struggling with high housing costs and utility debt,” said Alexis Sutterman, energy equity program manager at the California Environmental Justice Alliance.

The program has energy equity baked into its structure, working to make sure Californians of all income levels participate in the benefits of the energy transition. Not only does it open solar access to renters, the law ensures that at least 51% of subscribers are low-income customers, which is expected to make projects eligible for a 10% tax credit adder under the IRA.

“The money’s on the table now,” said Jeff Cramer, president and chief executive of the Coalition for Community Solar Access. “While there are groups pushing for solar access for all, and states with strong legislation, there are other pockets of interest in surprising places in the United States. For example, Louisiana has no policy for community solar or support for low-income residents going solar but the city of New Orleans has its own utility commission with a community solar program. In Nebraska, forward-looking co-operatives have created community solar projects.

Community solar markets are active in 22 states, with more expected to come online in the future as states pursue 100% clean energy targets across the country. However, the market is expected to require strong community outreach efforts to foster trust and gain subscribers.

“There is a distrust of community solar initially in LMI communities as many have been burned before by retail energy false promises,” said Eric LaMora, executive director, community solar, Nautilus Solar on a panel at the Solar Energy Industries Association Finance, Tax, and Buyers seminar. “People are suspicious but there really are no hooks with community solar.”

LMI residents are leery to provide tax records or much documents at all in order to sign up for community solar, LaMora said. “We were surprised to see less of a default rate with LMI residents. We attribute this to the fact that they see significant savings on their electric bill, making it easier to pay each month,” he said.

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Ontario-Quebec Energy Swap streamlines electricity exchange, balancing peak demand across clean grids with hydroelectric and nuclear power, enhancing reliability, capacity banking, and interprovincial load management for industry growth, EV adoption, and seasonal heating-cooling needs.

Key Points

10-year, no-cash power swap aligning peaks; hydro and nuclear enhance reliability and let Ontario bank capacity.

✅ Up to 600 MW exchanged yearly; reviews adjust volumes

✅ Peaks differ: summer A/C in Ontario, winter heating in Quebec

✅ Capacity banking enables future-year withdrawals

Ontario and Quebec have agreed to swap energy to build on an electricity deal to help each other out when electricity demands peak.

The provinces' electricity operators, the Independent Electricity System Operator holds capacity auctions and Hydro-Quebec, will trade up to 600 megawatts of energy each year, said Ontario Energy Minister Todd Smith.

“The deal just makes a lot of sense from both sides,” Smith said in an interview.

“The beauty as well is that Quebec and Ontario are amongst the cleanest grids around.”

The majority of Ontario's power comes from nuclear energy while the majority of Quebec's energy comes from hydroelectric power, including Labrador power in regional transmission networks.

The deal works because Ontario and Quebec's energy peaks come at different times, Smith said.

Ontario's energy demands spike in the summer, largely driven by air conditioning on hot days, and the province has occasionally set off-peak electricity prices to provide temporary relief, he said.

Quebec's energy needs peak in the winter, mostly due to electric heating on cold days.

The deal will last 10 years, with reviews along the way to adjust energy amounts based on usage.

“With the increase in energy demand, we must adopt more energy efficiency programs like Peak Perks and intelligent measures in order to better manage peak electricity consumption,” Quebec's Energy Minister Pierre Fitzgibbon wrote in a statement.

Smith said the energy deal is a straight swap, with no payments on either side, and won't reduce hydro bills as the transfer could begin as early as this winter.

Ontario will also be able to bank unused energy to save capacity until it is needed in future years, Smith said.

Both provinces are preparing for future energy needs, as electricity demands are expected to grow dramatically in the coming years with increased demand from industry and the rise of electric vehicles, and Ontario has tabled legislation to lower electricity rates to support consumers.

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