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COVID-19 Impact on U.S. Power Demand shows falling electricity load, lower wholesale prices, and resilient utilities in competitive markets, with regional differences tied to weather, renewable energy, stay-at-home orders, and hedging strategies.

Key Points

It outlines reduced load and prices, while regulatory design and hedging support utility stability across regions.

✅ Load down in NY, New England, PJM; weather drives South up.

✅ Wholesale prices fall 8-10% in key markets.

✅ Decoupling, contracts, hedging support utility earnings.

On March 27, Bloomberg New Energy Finance (BNEF) released a report on electricity demand and wholesale market prices impact from COVID-19 fallout. The model compares expected load based largely on weather with actual observed electricity demand changes.

So far, the hardest hit power grid is New York, with load down 7 and prices off by 10 percent. That’s expected, given New York City is the current epicenter of the US health crisis.

Next is New England, with 5 percent lower demand and 8 percent reduced wholesale prices for the week from March 19-25. BNEF says the numbers could go higher following advisories and orders issued March 24 for some 70 percent of the region’s population to stay at home.

Demand on the biggest grid in the US, the PJM (Pennsylvania/Jersey/Maryland), is 4 percent lower, with prices dropping 8 percent, as recent capacity auction payouts fell sharply. BNEF believes there will be more impact as stay at home orders are ramped up in several states.

California’s power demand for March 19-25 was 5 percent below what BNEF’s model expects without COVID-19 impact. That reflects a full week of stay-at-home orders from Governor Newsom issued March 19.

Health officials in Los Angeles and elsewhere expect a spike in COVID-19 cases in coming weeks. But BNEF’s model now actually projects rising electricity load for the state, due to what it calls "freakishly mild weather a year ago."

Rounding out the report, power demand is up for a band of southern states stretching from Florida to the desert Southwest, with weather more than offsetting public response to COVID-19 so far. BNEF says the Northwest’s grid "has not yet been highly impacted," while the Southeast is "generally in line" with pre-virus expectations.

Clearly, all of this data can change quickly and radically. Only California and New York are currently in full shutdown mode. Following them are New England (70 percent), the Midwest (65 percent), Texas (50 percent), PJM (50 percent) and the Northwest (50 percent).

In contrast, only small parts of Florida, the Southeast and Southwest are restricting movement. That could mean a big future increase for shut-ins, with heightened risks of electricity shut-offs that burden households and a corresponding impact on power demand.

Also, weather will play a major role on what happens to actual electricity demand, just as it always does. A very hot summer, for example, could offset virus-related shut-ins, just as it apparently is now in states like Texas. And it should be pointed out that regions vary widely by exposure to recession-sensitive sources of demand, such as heavy industry.

Most important for investors, however, is the built in protection US utility earnings enjoy from declining power demand, even amid broader energy crisis pressures facing the sector. For one thing, US power grids in California, ERCOT (Texas), MISO (Midwest), New England, New York and PJM have wholesale power markets, where producers compete for sales and the lowest bidder sets the price.

In those states, most regulated utilities don’t produce power at all. In fact, companies’ revenue is decoupled entirely from demand in California, as well as much of New England. In the roughly three-dozen states where utilities still operate as integrated monopolies, demand does affect revenue, and in many regions flat electricity demand already persists. But the cost of electricity is passed through directly to customers, whether produced or purchased.

A number of US electric companies have invested in renewable energy facilities as part of broader electrification trends nationwide. These sell their output under long-term contracts primarily with other utilities and government entities.

This isn’t a risk free business: For the past year, generators selling electricity to bankrupt PG&E Corp (PCG) have had their cash trapped at the power plant level as surety for lenders. But even PG&E has honored its contracts. And with states continuing aggressive mandates for renewable energy adoption, growth doesn’t appear at risk to COVID-19 fallout either.

The wholesale price of power from natural gas, coal and many nuclear plants was already sliding before COVID-19, due to renewables adoption and low natural gas prices, even as coal and nuclear disruptions raise reliability concerns. But here too, big producers like Exelon Corp (EXC) and Vistra Energy (VST) have employed aggressive price hedging near term, with regulated utilities and retail businesses protecting long-term health, respectively.

Bottom line: It’s early days for the COVID-19 crisis and much can still change. But so far at least, the US power industry is absorbing the blow of reduced demand, just as it’s done in previous crises.

That means future selloffs in the ongoing bear market are buying opportunities for best in class electric utilities, not a reason to sell. For top candidates, see the Conrad’s Utility Investor Portfolios and Dream Buy List in the March issue. 

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COVID-19 Solar Job Losses are erasing five years of workforce growth, SEIA reports, with U.S. installations and capacity down, layoffs accelerating, 3 GW expected in Q2, and policy support key for economic recovery.

Key Points

COVID-19 Solar Job Losses describe the pandemic-driven decline in U.S. solar employment, installations, and capacity.

✅ SEIA reports a 38% national drop in solar jobs

✅ Q2 installs projected at 3 GW, below forecasts

✅ Layoffs outpace U.S. economy without swift policy aid

Job losses associated with the COVID-19 crisis have wiped out the past five years of workforce growth in the solar energy field, according to a new industry analysis.

The expected June 2020 solar workforce of 188,000 people across the United States is 114,000 below the pre-pandemic forecast of 302,000 workers, a shortfall tied to the solar construction slowdown according to the Solar Energy Industries Association, which said in a statement Monday that the solar industry is now losing jobs at a faster rate than the U.S. economy.

In Massachusetts, the loss of 4,284 solar jobs represents a 52 percent decline from previous projections, according to the association’s analysis.

The national 38 percent drop in solar jobs coincides with a 37 percent decrease in expected solar installations in the second quarter of 2020, and similar pressures have put wind investments at risk across the sector, the association stated. The U.S. is now on track to install 3 gigawatts of new capacity this quarter, though subsequent forecasts anticipated solar and storage growth as investments returned, and the association said the decrease from the expected capacity is equivalent to the electricity needed to power 288,000 homes.

“Thousands of solar workers are being laid off each week, but with swift action from Congress, we know that solar can be a crucial part of our economic recovery,” with proposals such as the Biden solar plan offering a potential policy path, SEIA President and CEO Abigail Ross Hopper said in a statement, as recent analyses point to US solar and wind growth under supportive policies.

Subsequent data showed record U.S. panel shipments as the market rebounded.

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SM-1A Nuclear Plant Decommissioning details the US Army Corps of Engineers' removal of the Fort Greely reactor, Cold War facility dismantling, environmental monitoring, remote-site power history, and timeline to 2026 under a deactivated nuclear program.

Key Points

Army Corps plan to dismantle Fort Greely's SM-1A reactor and complete decommissioning of remaining systems by 2026.

✅ Built for remote Arctic radar support during the Cold War

✅ High costs beat diesel; program later deemed impractical

✅ Reactor parts removed; residuals monitored; removal by 2026

The US Army Corps of Engineers has begun decommissioning Alaska’s only nuclear power plant, SM-1A, which is located at Fort Greely, even as new US reactors continue to take shape nationwide. The $17m plant closed in 1972 after ten years of sporadic operation. It was out of commission from 1967 to 1969 for extensive repairs. Much of has already been dismantled and sent for disposal, and the rest, which is encased in concrete, is now to be removed.

The plant was built as part of an experimental programme to determine whether nuclear facilities, akin to next-generation nuclear concepts, could be built and operated at remote sites more cheaply than diesel-fuelled plants.

"The main approach was to reduce significant fuel-transportation costs by having a nuclear reactor that could operate for long terms, a concept echoed in the NuScale SMR safety evaluation process, with just one nuclear core," Brian Hearty said. Hearty manages the Army Corps of Engineers’ Deactivated Nuclear Power Plant Program.

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He said the Army built SM-1A in 1962 hoping to provide power reliably at remote Arctic radar sites, where in similarly isolated regions today new US coal plants may still be considered, intended to detect incoming missiles from the Soviet Union at the height of the Cold War. He added that the programme worked but not as well as Pentagon officials had hoped. While SM-1A could be built and operated in a cold and remote location, its upfront costs were much higher than anticipated, and it costs more to maintain than a diesel power plant. Moreover, the programme became irrelevant because of advances in Soviet rocket science and the development of intercontinental ballistic missiles.

Hearty said the reactor was partially dismantled soon after it was shut down. “All of the fuel in the reactor core was removed and shipped back to the Atomic Energy Commission (AEC) for them to either reprocess or dispose of,” he noted. “The highly activated control and absorber rods were also removed and shipped back to the AEC.”

The SM-1A plant produced 1.8MWe and 20MWt, including steam, which was used to heat the post. Because that part of the system was still needed, Army officials removed most of the nuclear-power system and linked the heat and steam components to a diesel-fired boiler. However, several parts of the nuclear system remained, including the reactor pressure vessel and reactor coolant pumps. “Those were either kept in place, or they were cut off and laid down in the tall vapour-containment building there,” Hearty said. “And then they were grouted and concreted in place.” The Corps of Engineers wants to remove all that remains of the plant, but it is as yet unclear whether that will be feasible.

Meanwhile, monitoring for radioactivity around the facility shows that it remains at acceptable levels. “It would be safe to say there’s no threat to human health in the environment,” said Brenda Barber, project manager for the decommissioning. Work is still in its early stages and is due to be completed in 2026 at the earliest. Barber said the Corps awarded the $4.6m contract in December to a Virginia-based firm to develop a long-range plan for the project, similar in scope to large reactor refurbishment efforts elsewhere. Among other things, this will help officials determine how much of the SM-1A will remain after it’s decommissioned. “There will still be buildings there,” she said. “There will still be components of some of the old structure there that may likely remain.”

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Washington County solar farm incentives aim to steer projects to industrial sites with tax breaks, underground grid connections, decommissioning bonds, and wildlife corridors, balancing zoning, historic preservation, and Maryland renewable energy mandates.

Key Points

Policies steer solar to industrial sites with tax breaks, buried lines, and bonds, aligning with zoning and state goals.

✅ Tax breaks to favor rooftops and parking canopies

✅ Bury new grid lines to shift projects to industrial parks

✅ Require decommissioning bonds and wildlife corridors

Incentives for establishing solar farms at industrial spaces instead of on prime farmland are among the ideas the Washington County Planning Commission is recommending for the county to update its policies regarding solar farms.

Potential incentives would include tax breaks on solar equipment and requiring developers to put power-grid connections and line extensions underground, a move tied to grid upgrade cost debates in other regions, Planning Commission members said during a Monday meeting.

The tax break could make it more attractive for a developer to put a solar farm on a roof or over a parking lot, similar to California's building-solar requirement policies that favor rooftop generation, which could cost more than putting it on farmland, said Commission member Dave Kline, who works for FirstEnergy.

Requiring a company to bury new transmission lines could steer them to industrial or business parks where, theoretically, transmission lines are more readily available, Kline said Wednesday in a phone interview.

Chairman Clint Wiley suggested talking to industrial property owners to create a list of industrial sites that make sense for a solar site, which could generate extra income for the property owner.

Commission members also talked about requiring a wildlife corridor. Anne Arundel County requires such a corridor if a solar site is over 15 acres, according to Jill Baker, deputy director of planning and zoning. The solar site is broken into sections so animals such as deer can get through, she said.

However, that means the solar farm would take up more agricultural land, Commission member Jeremiah Weddle said. Weddle, a farmer, has repeatedly voiced concerns about solar farms using prime farmland.

County zoning law already states solar farms are prohibited in Rural Legacy Areas, Priority Preservation Areas, and within Antietam Overlay zones that preserve the Antietam National Battlefield viewshed. They also cannot be built on land with permanent preservation easements, Baker said.

However, a big reason county officials are looking to strengthen county policies for solar generating systems, or solar farms, is a recent court decision that ruled the Maryland Public Service Commission can preempt county zoning law when it comes to large solar farms.

County zoning law defines a solar energy generating system as a solar facility, with multiple solar arrays, tied into the power grid and whose primary purpose is to generate power to distribute and/or sell into the public utility grid rather than consuming that power on site.

The Maryland Court of Appeals ruled in July that the Public Service Commission can preempt local zoning regarding solar farms larger than 2 megawatts. But the ruling also stated local government is a "significant participant in the process" and the state commission must give "due consideration" to local zoning laws.

County officials are looking at recommendations for solar farms, whether they are over 2 megawatts or not.

Solar farms are a popular issue statewide, especially with Maryland solar subscriptions expanding, and were discussed at a recent Maryland Association of Counties meeting for planners, Planning and Zoning Director Stephen Goodrich said.

The thinking is the best way for counties to express their opinions about a solar project is to participate in the state commission's local public hearings, where issues like how solar owners are paid often arise, Goodrich said. Another popular idea is for the county to continue to follow its process, which requires a public hearing for a special exception to establish a solar farm. That will help the county form an opinion, on individual cases, to offer the state commission, he said.

Recommendations discussed by the Planning Commission include:

A break on personal property taxes, which is on equipment, including affordable battery storage that can firm output, to steer developers away from areas where the county doesn't want solar farms. The Board of County Commissioners have been split on tax-break agreements for solar farms, with a majority recently granting a few.

Protecting valuable historic sites.

Requiring a decommissioning bond for removing the equipment at the end of the solar farm's life. The bond is protection in case the company goes bankrupt. The county commissioners have been making such a bond a requirement when granting recent tax breaks.

Looking at allowing solar farms in stormwater-management areas.

Other counties, particularly in Western Maryland and on the Eastern Shore, are having issues with solar farms even as research to improve solar and wind advances, because land is cheaper and there are wide-open spaces, Goodrich said.

Many solar projects are being developed or proposed because state lawmakers passed legislation requiring 50% of electricity produced in the state to come from renewable sources by 2030, and a federal plan to expand solar is also shaping expectations. Of that 50%, 14.5% is to come from solar energy.

In Maryland, the average number of homes that can be powered by 1 megawatt of solar energy is about 110, according to the Solar Energy Industries Association's website.

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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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Canada Clean Electricity Regulations allow flexible, technology-neutral pathways to a 2035 net-zero grid, permitting limited natural gas with carbon capture, strict emissions standards, and exemptions for emergencies and peak demand across provinces and territories.

Key Points

Federal draft rules for a 2035 net-zero grid, allowing limited gas with CCS under strict performance and compliance standards.

✅ Performance cap: 30 tCO2 per GWh annually for gas plants

✅ CCS must sequester 95% of emissions to comply

✅ Emergency and peak demand exemptions permitted

After facing pushback from Alberta and Saskatchewan, and amid looming power challenges nationwide, Canada's draft net-zero electricity regulations — released today — will permit some natural gas power generation. 

Environment Minister Steven Guilbeault released Ottawa's proposed Clean Electricity Regulations on Thursday.

Provinces and territories will have a minimum 75-day window to comment on the draft regulations. The final rules are intended to pave the way to a net-zero power grid in Canada, aligning with 2035 clean electricity goals established nationally. 

Calling the regulations "technology neutral," Guilbeault said the federal government believes there's enough flexibility to accommodate the different energy needs of Canada's diverse provinces and territories, including how Ontario is embracing clean power in its planning. 

"What we're talking about is not a fossil fuel-free grid by 2035; it's a net zero grid by 2035," Guilbeault said. 

"We understand there will be some fossil fuels remaining … but we're working to minimize those, and the fossil fuels that will be used in 2035 will have to comply with rigorous environmental and emission standards," he added. 

Some analysts argue that scrapping coal-fired electricity can be costly and ineffective, underscoring the trade-offs in transition planning.

While non-emitting sources of electricity — hydroelectricity, wind and solar and nuclear — should not have any issues complying with the regulations, natural gas plants will have to meet specific criteria.

Those operations, the government said, will need to emit the equivalent of 30 tonnes of carbon dioxide per gigawatt hour or less annually to help balance demand and emissions across the grid.

Federal officials said existing natural gas power plants could comply with that performance standard with the help of carbon capture and storage systems, which would be required to sequester 95 per cent of their emissions.

"In other words, it's achievable, and it is achievable by existing technology," said a government official speaking to reporters Thursday on background and not for attribution.

The regulations will also allow a certain level of natural gas power production without the need to capture emissions. Capturing emissions will be exempted during emergencies and peak periods when renewables cannot keep up with demand. 

Some newer plants might not have to comply with the rules until the 2040s, because the regulations apply to plants 20 years after they are commissioned, which dovetails with net-zero by 2050 commitments from electricity associations. 

The two-decade grace period does not apply to plants that open after the regulations are expected to be finalized in 2025.

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