A million without power following aftershock

U.S. Solar Generation 2017 surpassed biomass, delivering 77 million MWh versus 64 million MWh, trailing only hydro and wind; driven by PV expansion, capacity additions, and utility-scale and small-scale growth, per EIA.

Key Points

It was the year U.S. solar electricity exceeded biomass, hitting 77 million MWh and trailing only hydro and wind.

✅ Solar: 77 million MWh; Biomass: 64 million MWh (2017, EIA)

✅ PV expansion; late-year capacity additions dampen annual generation

✅ Hydro: 300 and wind: 254 million MWh; solar thermal ~3 million MWh

Electricity generation from solar resources in the United States reached 77 million megawatthours (MWh) in 2017, surpassing for the first time annual generation from biomass resources, which generated 64 million MWh in 2017. Among renewable sources, only hydro and wind generated more electricity in 2017, at 300 million MWh and 254 million MWh, respectively. Biomass generating capacity has remained relatively unchanged in recent years, while solar generating capacity has consistently grown.

Annual growth in solar generation often lags annual capacity additions because generating capacity tends to be added late in the year. For example, in 2016, 29% of total utility-scale solar generating capacity additions occurred in December, leaving few days for an installed project to contribute to total annual generation despite being counted in annual generating capacity additions. In 2017, December solar additions accounted for 21% of the annual total. Overall, solar technologies operate at lower annual capacity factors and experience more seasonal variation than biomass technologies.

Biomass electricity generation comes from multiple fuel sources, such as wood solids (68% of total biomass electricity generation in 2017), landfill gas (17%), municipal solid waste (11%), and other biogenic and nonbiogenic materials (4%).These shares of biomass generation have remained relatively constant in recent years, even as renewables' rise in 2020 across the grid.

Solar can be divided into three types: solar thermal, which converts sunlight to steam to produce power; large-scale solar photovoltaic (PV), which uses PV cells to directly produce electricity from sunlight; and small-scale solar, which are PV installations of 1 megawatt or smaller. Generation from solar thermal sources has remained relatively flat in recent years, at about 3 million MWh, even as renewables surpassed coal in 2022 nationwide. The most recent addition of solar thermal capacity was the Crescent Dunes Solar Energy plant installed in Nevada in 2015, and currently no solar thermal generators are under construction in the United States.

Solar photovoltaic systems, however, have consistently grown in recent years, as indicated by 2022 U.S. solar growth metrics across the sector. In 2014, large-scale solar PV systems generated 15 million MWh, and small-scale PV systems generated 11 million MWh. By 2017, annual electricity from those sources had increased to 50 million MWh and 24 million MWh, respectively, with projections that solar could reach 20% by 2050 in the U.S. mix. By the end of 2018, EIA expects an additional 5,067 MW of large-scale PV to come online, according to EIA’s Preliminary Monthly Electric Generator Inventory, with solar and storage momentum expected to accelerate. Information about planned small-scale PV systems (one megawatt and below) is not collected in that survey.

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U.S. Energy Crunch disrupts fuel and power markets, driving natural gas price spikes, coal resurgence, utility mix shifts, supply chain strains for EV batteries, and inflation pressures, complicating climate policy, OPEC outreach and LNG trade

Key Points

Supply-demand gaps raise fuel costs, revive coal, strain EV materials, and complicate U.S. climate policy and plans.

✅ Natural gas spikes shift generation from gas to coal

✅ Supply chain shortages hit nickel, silicon, and chips

✅ Policy tensions between price relief and decarbonization

A global energy crunch is creating pain for people struggling to fill their tanks and heat their homes, as well as roiling the utility industry’s plans to change its mix of generation and complicating the Biden administration’s plans to tackle climate change.

The ripple effects of a surge in natural gas prices include a spike in coal use and emissions that counter clean energy targets. High fossil fuel prices also are translating into high prices and a supply crunch for key minerals like silicon used in clean energy projects. On a call with investors yesterday, a Tesla Inc. executive said the company is having a hard time finding enough nickel for batteries.

The crisis could pose political problems for the Biden administration, which spent the last few months fending off criticism about rising fuel prices and inflation (Energywire, Oct. 14).

“Energy issues at this moment are as salient to the American public as they have been in quite some time,” said Christopher Borick, who directs the Muhlenberg College Institute of Public Opinion in Pennsylvania, where Biden stopped yesterday to pitch his infrastructure plan.

While gasoline prices have gotten headlines all summer, natural gas prices have risen faster than motor fuels, more than doubling from an average $1.92 per thousand cubic feet in September 2020 to $5.16 last month. By comparison, gasoline prices have risen about 55 percent in the last year, to $3.36 per gallon nationwide this week, according to AAA.

The roots of the problem go back to the beginning of the pandemic and the recession in 2020. Oil and gas prices fell so fast then that many producers, particularly in the U.S., simply stopped drilling.

Oil companies began predicting a few months later that the abrupt shutdown would eventually lead to shortages and price spikes when the economy recovered. Those predictions turned out to be accurate.

With the economy beginning to recover, demand for gas has gone up, but there’s not enough supply to go around.

While the U.S. energy crunch isn’t as severe as Europe’s energy crisis today, and analysts predict that gas prices will gradually fall next year, consumers could be in for a rough couple of months.

Here’s four ways the global energy crisis is impacting the United States, from the electricity sector to the political landscape:

What are the political repercussions?
For the Biden administration, the energy price hikes come amid fears of rising inflation and persistent supply bottlenecks at the nation’s ports as its climate ambitions face headwinds in Congress.

“The confluence of energy prices, logistical challenges and the need to move on climate have raised this to the top tier,” said Borick, who in the past has polled on energy and environmental issues in Pennsylvania.

Borick noted the administration is facing counterpressures: Even as it pushes to decarbonize the nation’s electric system, it wants to keep gas prices in check. High gasoline prices have been linked to declining political approval ratings, including for presidents, even if much of the price hikes are beyond their control.

White House press secretary Jen Psaki said earlier this month that the administration can take steps to address what it called “short-term supply issues,” but also needs to focus on the long term — and climate.

In hopes of capping prices, the White House has spoken with members of OPEC about increasing oil production — though OPEC has little control over natural gas prices. And earlier this month, the administration talked to U.S. oil and gas producers about helping to bring down prices.

That comes even as environmentalists have pushed Biden to ban federal fossil fuel leasing and drilling and stop new projects.

The moves to curb prices have prompted ridicule from Republicans, who have accused Biden of declaring war on U.S. energy by canceling the Keystone XL pipeline.

“The Biden administration won’t say it out loud, yet let’s admit it: There is a crisis,” Sen. John Barrasso (R-Wyo.) said this week on the Senate floor. “It is one that Joe Biden and his administration has created. It is a crisis of Joe Biden’s own making.”

The situation has also resurfaced comparisons to former President Carter, who struggled politically in the 1970s with gasoline shortages and other energy pressures. Some political scientists say, though, the comparison between the two isn’t apples to apples.

"In 1979, the crisis began with the Iranian Revolution, producing a supply shortage. In the USA, some states rationed the supply. That’s not occurring now. Oil prices were also regulated, another difference, “ said Terry Madonna, a senior fellow in residence for political affairs at Millersville University.

A Morning Consult poll released yesterday carried warning signs for Democrats with worries about the economy on the rise across the political spectrum.

Voters, however, were evenly split on how Biden is handling energy. Forty-two percent of respondents approve of Biden’s energy policy, compared with 45 percent who disapproved. The margin of error is 2 percentage points.

Will the electricity mix change?
Higher gas prices are giving coal a boost in some markets.

Atlanta-based Southern Co. told CNBC earlier this week, for instance, that coal was about 17 percent of the company’s power mix last year. That has changed in 2021.

“The unintended consequence of high gas prices is that coal becomes more economic, and so my sense is … our coal production has bumped up above 20 percent,” Southern CEO Tom Fanning said. “Now, how long that’ll persist, I don’t know.”

Fanning said “what we’re seeing right now, and the real challenge in America, is this notion of energy in transition.”

But the U.S. power sector has been evolving for years, with more renewables and less coal on the grid, and experts say the current energy crunch won’t change long-term utility trends in the industry.

“In general, I wouldn’t place too much emphasis on short-term fluctuations,” Jay Apt, a professor at Carnegie Mellon University, said in an email. “There is still a robust supply chain for most components needed for low-pollution power, including renewables.”

In fact, elevated fossil fuel prices, and high natural gas prices in particular, could accelerate the move toward wind, solar and batteries in some areas. That’s because power plants that run on coal and natural gas can be affected by rising and volatile fuel prices, as illustrated by the recent move in commodities globally. That means higher costs to run the facilities, even if power prices often climb along with gas prices.

“If I were a utility planner, this would cause me to double down on new generation from [wind] and solar and storage as opposed to building additional natural gas plants where, you know, I could be having these super high and volatile operating costs,” said Bri-Mathias Hodge, an associate professor in the Department of Electrical, Computer and Energy Engineering at the University of Colorado, Boulder.

Ed Hirs, an energy fellow at the University of Houston, said the current global situation doesn’t change the U.S. power sector’s overall move toward generation with lower operating costs.

For example, he said nuclear and coal plants can require hundreds of employees, and both have fuel costs. Hirs said a gas facility also needs fuel and may need dozens of employees. Wind and solar facilities often need a smaller number of workers and don’t require fuel in their operations, he noted.

“Eventually the cheap wins out,” Hirs said.

That isn’t even factoring in climate change — the reason world leaders are seeking to slash greenhouse gas emissions. Indeed, lowering emissions remains a priority among many states and big companies in the U.S.

Over the next 10 to 15 years, Hirs said, a key question will be whether battery technology can compete economically in terms of backing up renewables. He said a national carbon price, if enacted, would aid renewables and enhance returns on batteries.

“The real battle is going to be between natural gas and battery storage,” Hirs said.

Apt and M. Granger Morgan, who’s also a Carnegie Mellon professor, noted in a Hill piece last month that the U.S. gets about 40 percent of its power from carbon-free sources, including nuclear.

“Modelers and many power system operators agree that it is possible that renewables can cost-effectively make up roughly 80% of electricity generation,” the professors wrote, adding that other sources could include “storage and gas turbines powered with hydrogen, synfuels, or natural gas with carbon capture.”

What about EVs and renewables?
As for electric vehicles, executives with Tesla said on a call yesterday that supply-chain problems are the major brake on production for both vehicles and batteries.

Chief Financial Officer Zachary Kirkhorn said that the company’s factories aren’t running at full capacity because of an ongoing shortage of semiconductor chips. Customers are waiting longer for vehicles, he said, and wait lists are growing.

The challenges extend to raw materials. In batteries, Kirkhorn said, the company is having trouble finding enough nickel, and in vehicles, it is scrounging for aluminum. He said the problem is "not small," and that prices may rise as supply contracts come up for renewal.

The supply problems are creating "cost headwinds," he said, and so are rising labor costs. Tesla is not immune from the worker shortages that are plaguing the entire U.S. economy.

The production woes aren’t limited to Tesla: Automakers around the world have have had their output crimped by the chip shortage that accompanied the economic rebound after pandemic lockdowns. Unlike many other automakers, Tesla hasn’t been forced to pause its factory lines.

Tesla said it is poised to greatly expand its production of batteries for the electric grid — with a caveat.

Last month, Tesla broke ground on a new California factory to make Megapack, its 3 megawatt-per-hour lithium-ion batteries for use by power companies. That future factory’s capacity, 40 gigawatt per hour a year, is vastly more than the 3 GWh it made in the last calendar year.

However, today’s supply-chain problems are braking the making of both Megapack and Powerwall, Tesla’s battery for homes, Kirkhorn said. He added that production will increase "as soon as parts allow us."

Other advocates for EVs and renewable power expressed little concern about the supply crunch’s meaning for their industries, noting that higher prices alone don’t automatically trigger a broader green revolution on their own.

Those problems likely wouldn’t change the immediate course of the energy transition, researchers said.

"Short-term trends, week to week or even month to month, don’t matter much for investors or policy makers," wrote John Graham, a former budget official with the Bush administration and professor at Indiana University’s O’Neill School of Public and Environmental Affairs, in an email to E&E News.

The crunch may give policymakers a glimpse of the future, however, according to one minerals analyst.

"This isn’t going to be an outlier. I think increasingly you’re going to see pockets of the world start to feel these strains," said Andrew Miller, product director at Benchmark Mineral Intelligence, which focuses its research on battery minerals and battery supply chains.

The U.S. and its allies are only now beginning to develop their own supply chains for batteries and other key clean energy technologies, he noted. "The issue you’re facing, and this is one coming over time, is to have the platform in place. You have to have the supply chain of raw materials," he said.

"I think you’re going to see the most turbulence over the coming decade. … It’s not going to be a smooth transition,” added Miller.

How long will gas prices stay high?
The gap between natural gas demand and supply has led to severe price spikes in Europe, where utilities and other gas buyers have to compete against China for cargoes of liquefied natural gas, according to a research note from IHS Markit Ltd.

Here in the U.S., the causes are the same, but the results aren’t as extreme. Less than 10 percent of domestic gas production is exported as LNG, so American customers don’t have to compete as much against overseas buyers.

Instead, gas-hungry sectors of the economy have run into another problem, IHS analyst Matthew Palmer said in an interview. Gas producers have been cautious about increasing their output, largely because of pressure from investors to limit their spending.

“That theme has really put a governor on production,” he said.

The disconnect will likely mean higher home gas bills and higher electric prices this winter, although deep freeze events or warm weather could disrupt the trend, he said. The U.S. Energy Information Administration is predicting that average heating bills for homes that use gas furnaces will rise 30 percent this winter.

This comes as U.S. gas supply remains high, according to a biennial assessment from the Potential Gas Committee, a group of volunteer geoscientists, engineers and other experts.

Including reserves, future gas supply in the U.S. stands at a record 3,863 trillion cubic feet, up 25 tcf from levels reported in 2019, the group said Tuesday at an event co-hosted with the American Gas Association.

Of that total, so-called technically recoverable resources — or those in the ground but not yet recovered — are 3,368 tcf, the PGC said, down less than 0.2 percent from the last assessment.

The amount of technically recoverable gas went relatively unchanged from year-end 2018 for several reasons, including a lack of company activity in exploration efforts last year due to COVID, said Alexei Milkov, the group’s executive director.

Another factor is that basins mature and shale plays “cannot increase in resources forever,” said Milkov, also a professor of geology and geological engineering at the Colorado School of Mines.

Still, Milkov added, “We cannot tell you right now if we are on a new plateau, or if we are going to start seeing more growth in gas resources again, right, because it’s a complex issue.”

The EIA predicts that gas production will increase and prices will begin to drop in 2022.

David Flaherty, CEO of the Republican polling firm Magellan Strategies in Colorado, said prices could particularly hit seniors. But he said he expected the energy crunch to ease in the U.S. well before the election.

“By early summer, this is likely to be behind us,” he said.

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California Electricity Rate Hikes strain households as CPUC weighs fixed charges, utility profit caps, and stricter oversight. Wildfire mitigation, transmission upgrades, and aging grid costs push bills higher amid renewable integration and consumer protection debates.

Key Points

California power rates are rising from wildfire mitigation, transmission costs, and grid upgrades under CPUC review.

✅ CPUC mulls fixed charges to stabilize bills and rate design.

✅ Advocates push profit caps; utilities cite investment needs.

✅ Stronger oversight sought to curb waste and boost transparency.

California residents and consumer groups are demanding relief as their electricity bills continue to climb, putting increasing pressure on state regulators to intervene.  A recent op-ed in the San Francisco Chronicle highlights the growing frustration, emphasizing that California already has some of the highest electricity rates in the country, as coverage on why prices are soaring underscores, and these costs are only getting more burdensome.

Factors Driving High Bills

The rising electricity bills are attributed to several factors:

• Wildfire Mitigation and Liability: Utility companies are investing heavily in wildfire prevention measures, such as vegetation management and infrastructure hardening. The costs of these initiatives, along with the increasing financial liabilities associated with wildfire risk, are being passed on to consumers.
• Transmission Costs: California's vast geography and move towards renewable energy sources necessitate significant investments in transmission lines to deliver electricity from remote locations. These infrastructure costs also contribute to higher bills.
• Aging Infrastructure: California's electricity grid is aging and requires upgrades and maintenance, and the expenses associated with these efforts are reflected in consumer rates.

Proposed Solutions and Debates

Consumer advocates and some lawmakers are calling for various actions to address the issue, including a potential revamp of electricity rates to clean the grid:

• Fixed Charge Proposal: The California Public Utilities Commission (CPUC) is considering a proposal to introduce an income-based fixed charge on electricity bills. This change aims to make rates more predictable and encourage investment in renewable energy sources. However, opponents argue that it could disproportionately impact low-income households and discourage conservation.
• Utility Profit Caps: Some advocate for capping utility companies' profits. They believe excessive profits should be returned to customers in the form of lower rates. However, utility companies counter that they need a certain level of profit to invest in infrastructure and maintain a reliable grid.
• Increased Oversight: Consumer groups are calling for stricter oversight of utility company spending, and legislators are preparing to crack down on utility spending through upcoming votes as well. They demand transparency and want to ensure that funds collected from customers are being used for necessary investments and not for lobbying or excessive executive compensation.

Comparisons and National Implications

Similar concerns about rising utility bills are emerging in other parts of the country as more states transition to renewable energy and invest in infrastructure upgrades.

A report by the Energy Information Administration (EIA) shows that average residential electricity rates across the country have been on the rise for the past decade. While California currently ranks amongst the highest, major changes to electric bills are being debated, and other states are following suit, demonstrating the nationwide challenge of balancing affordability with necessary investments.

Uncertain Future

The California Public Utilities Commission is reviewing the fixed charge proposal and is expected to make a decision later this year, with income-based flat-fee utility bills moving closer in the process. The outcome of this decision and potential additional regulatory changes will have significant ramifications for California residents, and some lawmakers plan to overturn income-based charges if adopted, which could set a precedent for how other states handle the rising costs associated with the energy transition.

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Ontario Nuclear Power Costs highlight LCOE, capex, refurbishment outlays, and waste management, compared with renewables, grid reliability, and emissions targets, informing Australia and Peter Dutton on feasibility, timelines, and electricity prices.

Key Points

They include high capex and LCOE from refurbishments and waste, offset by reliable, low-emission baseload.

✅ Refurbishment and maintenance drive lifecycle and LCOE variability.

✅ High capex and long timelines affect consumer electricity prices.

✅ Low emissions, but waste and safety compliance add costs.

Australian opposition leader Peter Dutton recently lauded Canada’s use of nuclear power as a model for Australia’s energy future. His praise comes as part of a broader push to incorporate nuclear energy into Australia’s energy strategy, which he argues could help address the country's energy needs and climate goals. However, the question arises: Is Ontario’s experience with nuclear power as cost-effective as Dutton suggests?

Dutton’s endorsement of Canada’s nuclear power strategy highlights a belief that nuclear energy could provide a stable, low-emission alternative to fossil fuels. He has pointed to Ontario’s substantial reliance on nuclear power, and the province’s exploration of new large-scale nuclear projects, as an example of how such an energy mix might benefit Australia. The province’s energy grid, which integrates a significant amount of nuclear power, is often cited as evidence that nuclear energy can be a viable component of a diversified energy portfolio.

The appeal of nuclear power lies in its ability to generate large amounts of electricity with minimal greenhouse gas emissions. This characteristic aligns with Australia’s climate goals, which emphasize reducing carbon emissions to combat climate change. Dutton’s advocacy for nuclear energy is based on the premise that it can offer a reliable and low-emission option compared to the fluctuating availability of renewable sources like wind and solar.

However, while Dutton’s enthusiasm for the Canadian model reflects its perceived successes, including recent concerns about Ontario’s grid getting dirtier amid supply changes, a closer look at Ontario’s nuclear energy costs raises questions about the financial feasibility of adopting a similar strategy in Australia. Despite the benefits of low emissions, the economic aspects of nuclear power remain complex and multifaceted.

In Ontario, the cost of nuclear power has been a topic of considerable debate. While the province benefits from a stable supply of electricity due to its nuclear plants, studies warn of a growing electricity supply gap in coming years. Ontario’s experience reveals that nuclear power involves significant capital expenditures, including the costs of building reactors, maintaining infrastructure, and ensuring safety standards. These expenses can be substantial and often translate into higher electricity prices for consumers.

The cost of maintaining existing nuclear reactors in Ontario has been a particular concern. Many of these reactors are aging and require costly upgrades and maintenance to continue operating safely and efficiently. These expenses can add to the overall cost of nuclear power, impacting the affordability of electricity for consumers.

Moreover, the development of new nuclear projects, as seen with Bruce C project exploration in Ontario, involves lengthy and expensive construction processes. Building new reactors can take over a decade and requires significant investment. The high initial costs associated with these projects can be a barrier to their economic viability, especially when compared to the rapidly decreasing costs of renewable energy technologies.

In contrast, the cost of renewable energy has been falling steadily, even as debates over nuclear power’s trajectory in Europe continue, making it a more attractive option for many jurisdictions. Solar and wind power, while variable and dependent on weather conditions, have seen dramatic reductions in installation and operational costs. These lower costs can make renewables more competitive compared to nuclear energy, particularly when considering the long-term financial implications.

Dutton’s praise for Ontario’s nuclear power model also overlooks some of the environmental and logistical challenges associated with nuclear energy. While nuclear power generates low emissions during operation, it produces radioactive waste that requires long-term storage solutions. The management of nuclear waste poses significant environmental and safety concerns, as well as additional costs for safe storage and disposal.

Additionally, the potential risks associated with nuclear power, including the possibility of accidents, contribute to the complexity of its adoption. The safety and environmental regulations surrounding nuclear energy are stringent and require continuous oversight, adding to the overall cost of maintaining nuclear facilities.

As Australia contemplates integrating nuclear power into its energy mix, it is crucial to weigh these financial and environmental considerations. While the Canadian model provides valuable insights, the unique context of Australia’s energy landscape, including its existing infrastructure, energy needs, and the costs of scrapping coal-fired electricity in comparable jurisdictions, must be taken into account.

In summary, while Peter Dutton’s endorsement of Canada’s nuclear power model reflects a belief in its potential benefits for Australia’s energy strategy, the cost-effectiveness of Ontario’s nuclear power experience is more nuanced than it may appear. The high capital and maintenance costs associated with nuclear energy, combined with the challenges of managing radioactive waste and ensuring safety, present significant considerations. As Australia evaluates its energy future, a comprehensive analysis of both the benefits and drawbacks of nuclear power will be essential to making informed decisions about its role in the country’s energy strategy.

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California Public Safety Power Shutoffs highlight wildfire prevention as PG&E outages disrupt schools, businesses, and rural communities, driving generator use, economic hardship, and emergency preparedness across Northern California during high-wind events.

Key Points

Utility outages to reduce wildfire risk during extreme winds, impacting homes and businesses in high-risk California.

✅ PG&E cuts power during high winds to prevent wildfires

✅ Costs rise for generators, fuel, batteries, and spoiled food

✅ Rural, low-income communities face greater economic losses

The intentional blackout by California’s largest utility this week put Forest Jones out of work and his son out of school. On Friday morning Mr. Jones, a handyman and single father, sat in his apartment above a tattoo parlor waiting for the power to come back on and for school to reopen.

“I’ll probably lose $400 or $500 dollars because of this,” said Mr. Jones, who lives in the town of Paradise, which was razed by fire last year and is slowly rebuilding. “Things have been really tough up here.”

Millions of people were affected by the blackout, which spanned the outskirts of Silicon Valley to the forests of Humboldt County near the Oregon border. But the outage, which the power company said was necessary to reduce wildfire risk across the region, also drew a line between those who were merely inconvenienced and those who faced a major financial hardship.

To have the lights on, the television running and kitchen appliances humming is often taken for granted in America, even as U.S. grid during coronavirus questions persisted. During California’s blackout it became an economic privilege.

The economic impacts of the shut-off were especially acute in rural, northern towns like Paradise, where incomes are a fraction of those in the San Francisco Bay Area.

Both wealthy and poorer areas were affected by the blackout but interviews across the state suggested that being forced off the grid disproportionately hurt the less affluent. One family in Humboldt County said they had spent $150 on batteries and water alone during the shutdown.

“To be prepared costs money,” Sue Warhaftig, a massage therapist who lives in Mill Valley, a wealthy suburb across the Golden Gate Bridge from San Francisco. Ms. Warhaftig spent around two days without electricity but said she had been spared from significant sacrifices during the blackout.

She invested in a generator to keep the refrigerator running and to provide some light. She cooked in the family’s Volkswagen camper van in her driveway. At night she watched Netflix on her phone, which she was able to charge with the generator. Her husband, a businessman, is in London on a work trip. Her two sons, both grown, live in Southern California and Seattle.

“We were inconvenienced but life wasn’t interrupted,” Ms. Warhaftig said. “But so many people’s lives were.

Pacific Gas & Electric restored power to large sections of Northern California on Friday, including Paradise, where the electricity came back on in the afternoon. But hundreds of thousands of people in other areas remained in the dark. The carcasses of burned cars still littered the landscape around Paradise, where 86 people died in the Camp Fire last year, some of them while trying to escape.

Officials at power company said that by Saturday they hoped to have restored power to 98 percent of the customers who were affected.

The same dangerous winds that spurred the shut-off in Northern California have put firefighters to work in the south. The authorities in Los Angeles County ordered the evacuation of nearly 100,000 people on Friday as the Saddleridge Fire burned nearly 5,000 acres and destroyed 25 structures. The Sandalwood Fire, which ignited Thursday in Riverside County, had spread to more than 800 acres and destroyed 74 structures by Friday afternoon.

While this week’s outage was the first time many customers in Northern California experienced a deliberate power shut-off, residents in and around Paradise have had their power cut four times in recent months, residents say.

Many use a generator, but running one has become increasingly expensive with gasoline now at more than $4 a gallon in California.

On Friday, Dennis and Viola Timmer drove up the hill to their home in Magalia, a town adjacent to Paradise, loaded with $102 dollars of gasoline for their generators. It was their second gasoline run since the power went out Tuesday night.

The couple, retired and on a fixed income after Mr. Timmer’s time in the Navy and in construction, said the power outage had severely limited their ability to do essential tasks like cooking, or to leave the house.

“You know what it feels like? You’re in jail,” said Ms. Timmer, 72. “You can’t go anywhere with the generators running.”

Since the generators are not powerful enough to run heat or air conditioning, the couple slept in their den with an electric space heater.

“It’s really difficult because you don’t have a normal life,” Ms. Timmer said. “You’re trying to survive.”

To be sure, the shutdown has affected many people regardless of economic status, and similar disruptions abroad, like a London power outage that disrupted routines, show how widespread such challenges can be. The areas without power were as diverse as the wealthy suburbs of Silicon Valley, the old Gold Rush towns of the Sierra Nevada, the East Bay of San Francisco and the seaside city of Arcata.

Ms. Cahn’s cellphone ran out of power during the blackout and even when she managed to recharge it in her car cell service was spotty, as it was in many areas hit by the blackout.

Accustomed to staying warm at night with an electric blanket, Ms. Cahn slept under a stack of four blankets.

“I’m doing what I have to do which is not doing very much,” she said.

Further south in Marin City, Chanay Jackson stood surrounded by fumes from generators still powering parts of the city.

She said that food stamps were issued on the first of the month and that many residents who had to throw away food were out of luck.

“They’re not going to issue more food stamps just because the power went out,” Ms. Jackson said. “So they’re just screwed until next month.”

Strong winds have many times in the past caused power lines to come in contact with vegetation, igniting fires that are then propelled by the gusts, and hurricanes elsewhere have crippled infrastructure with Louisiana grid rebuild after Laura according to state officials. This was the case with the Camp Fire.

Since higher elevations had more extreme winds many of the neighborhoods where power was turned off this week were in hills and canyons, including in the Sierra Nevada.

The shut-off, which by one estimate affected a total of 2.5 million people, has come under strong criticism by residents and politicians, and warnings from Cal ISO about rolling blackouts as the power grid strained. The company’s website crashed just as customers sought information about the outage. Gov. Gavin Newsom called it unacceptable. But his comments were nuanced, criticizing the way the shut-off was handled, not the rationale for it. Mr. Newsom and others said the ravages of the Camp Fire demanded preventive action to prevent a reoccurrence.

Yet the calculus of trying to avoid deadly fires by shutting off power will continue to be debated as California enters its peak wildfire season, even as electricity reliability during COVID-19 was generally maintained for most consumers.

In the city of Grass Valley, Matthew Gottschalk said he and his wife realized that a generator was essential when they calculated that they had around $500 worth of food in their fridge.

“I don’t know what we would have done,” said Mr. Gottschalk, whose power went out Tuesday night.

His neighbors are filling coolers with ice. Everyone is hoping the power will come back on soon.

“Ice is going to run out and gas is going to run out,” he said.

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Power-to-gas converts surplus renewable electricity into green hydrogen or synthetic methane via electrolysis and methanation, enabling seasonal energy storage, grid balancing, hydrogen injection into gas pipelines, and decarbonization of heat, transport, and industry.

Key Points

Power-to-gas turns excess renewable power into hydrogen or methane for storage, grid support, and clean fuel.

✅ Enables hydrogen injection into existing natural gas networks

✅ Balances grids and provides seasonal energy storage capacity

✅ Supplies low-carbon fuels for industry, heat, and heavy transport

Last month Denmark’s biggest energy firm, Ørsted, said wind farms it is proposing for the North Sea will convert some of their excess power into gas. Electricity flowing in from offshore will feed on-shore electrolysis plants that split water to produce clean-burning hydrogen, with oxygen as a by-product. That would supply a new set of customers who need energy, but not as electricity. And it would take some strain off of Europe’s power grid as it grapples with an ever-increasing share of hard-to-handle EU wind and solar output on the grid.

Turning clean electricity into energetic gases such as hydrogen or methane is an old idea that is making a comeback as renewable power generation surges and crowds out gas in Europe. That is because gases can be stockpiled within the natural gas distribution system to cover times of weak winds and sunlight. They can also provide concentrated energy to replace fossil fuels for vehicles and industries. Although many U.S. energy experts argue that this “power-to-gas” vision may be prohibitively expensive, some of Europe’s biggest industrial firms are buying in to the idea.

European power equipment manufacturers, anticipating a wave of renewable hydrogen projects such as Ørsted’s, vowed in January that, as countries push for hydrogen-ready power plants across Europe, all of their gas-fired turbines will be certified by next year to run on up to 20 percent hydrogen, which burns faster than methane-rich natural gas. The natural gas distributors, meanwhile, have said they will use hydrogen to help them fully de-carbonize Europe’s gas supplies by 2050.

Converting power to gas is picking up steam in Europe because the region has more consistent and aggressive climate policies and evolving electricity pricing frameworks that support integration. Most U.S. states have goals to clean up some fraction of their electricity supply; coal- and gas-fired plants contribute a little more than a quarter of U.S. greenhouse gas emissions. In contrast, European countries are counting on carbon reductions of 80 percent or more by midcentury—reductions that will require an economywide switch to low-carbon energy.

Cleaning up energy by stripping the carbon out of fossil fuels is costly. So is building massive new grid infrastructure, including transmission lines and huge batteries, amid persistent grid expansion woes in parts of Europe. Power-to-gas may be the cheapest way forward, complementing Germany’s net-zero roadmap to cut electricity costs by a third. “In order to reach the targets for climate protection, we need even more renewable energy. Green hydrogen is perceived as one of the most promising ways to make the energy transition happen,” says Armin Schnettler, head of energy and electronics research at Munich-based electric equipment giant Siemens.

Europe already has more than 45 demonstration projects to improve power-to-gas technologies and their integration with power grids and gas networks. The principal focus has been to make the electrolyzers that convert electricity to hydrogen more efficient, longer-lasting and cheaper to produce.

The projects are also scaling up the various technologies. Early installations converted a few hundred kilowatts of electricity, but manufacturers such as Siemens are now building equipment that can convert 10 megawatts, which would yield enough hydrogen each year to heat around 3,000 homes or fuel 100 buses, according to financial consultancy Ernst & Young.

The improvements have been most dramatic for proton-exchange membrane electrolyzers, which are akin to the fuel cells used in hydrogen vehicles (but optimized to produce hydrogen rather than consume it). The price of proton-exchange electrolyzers has dropped by roughly 40 percent during the past decade, according to a study published in February in Nature Energy. They are also five times more compact than older alkaline electrolysis plants, enabling onsite hydrogen production near gas consumers, and they can vary their power consumption within seconds to operate on fluctuating wind and solar generation.

Many European pilot projects are demonstrating “methanation” equipment that converts hydrogen to methane, too, which can be used as a drop-in replacement for natural gas. Europe’s electrolyzer plants, however, are showing that methanation is not as critical to the power-to-gas vision as advocates long believed. Many electrolyzers are injecting their hydrogen directly into natural gas pipelines—something that U.S. gas firms forbid—and they are doing so without impacting either the gas infrastructure or natural gas consumers.

Europe’s first large-scale hydrogen injection began in eastern Germany in 2013 at a two-megawatt electrolyzer installed by Essen-based power firm E.ON. Germany has since ratcheted up the amount of hydrogen it allows in natural gas lines from an initial 2 percent by volume to 10 percent, in a market where renewables now outpace coal and nuclear in Germany, and other European states have followed suit with their own hydrogen allowances. Christopher Hebling, head of hydrogen technologies at the Freiburg-based Fraunhofer Institute for Solar Energy Systems, predicts that such limits will rise to the 20-percent level anticipated by Europe’s turbine manufacturers.

Moving renewable hydrogen and methane via natural gas pipelines promises to cut the cost of switching to renewable energy. For example, gas networks have storage caverns whose reserves could be tapped to run gas-fired electric generation power plants during periods of low wind and solar output. Hebling notes that Germany’s gas network can store 240 terawatt-hours of energy—roughly 25 times more energy than global power grids can presently store by pumping water uphill to refill hydropower reservoirs. Repurposing gas infrastructure to help the power system could save European consumers 138 billion euros ($156 billion) by 2050, according to Dutch energy consultancy Navigant (formerly Ecofys).

For all the pilot plants and promise, renewable hydrogen presently supplies a tiny fraction of Europe’s gas. And, globally, around 4 percent of hydrogen is supplied via electrolysis, with the bulk refined from fossil fuels, according to the International Renewable Energy Agency.

Power-to-gas is catching up, however. According to the February Nature Energy study, renewable hydrogen already pays for itself in some niche applications, and further electrolyzer improvements will progressively extend its market. “If costs continue to decline as they have done in recent years, power-to-gas will become competitive at large scale within the next decade,” says study co-author Gunther Glenk, an economist at the Technical University of Munich.

Glenk says power-to-gas could scale up faster if governments guaranteed premium prices for renewable hydrogen and methane, as they did to mainstream solar and wind power.

Tim Calver, an energy storage researcher turned consultant and Ernst & Young’s executive director in London, agrees that European governments need to step up their support for power-to-gas projects and markets. Calver calls the scale of funding to date, “not proportionate to the challenge that we face on long-term decarbonization and the potential role of hydrogen.”

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