U.S. power industry sees growth despite lean times

Power Grid Climate Resilience demands storm hardening, underground power lines, microgrids, batteries, and renewable energy as regulators and utilities confront climate change, sea level rise, and extreme weather to reduce outages and protect vulnerable communities.

Key Points

It is the grid capacity to resist and recover from climate hazards using buried lines, microgrids, and batteries.

✅ Underground lines reduce wind outages and wildfire ignition risk.

✅ Microgrids with solar and batteries sustain critical services.

✅ Regulators balance cost, resilience, equity, and reliability.

Every time a storm lashes the Carolina coast, the power lines on Tonye Gray’s street go down, cutting her lights and air conditioning. After Hurricane Florence in 2018, Gray went three days with no way to refrigerate medicine for her multiple sclerosis or pump the floodwater out of her basement.

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“Florence was hell,” said Gray, 61, a marketing account manager and Wilmington native who finds herself increasingly frustrated by the city’s vulnerability.

“We’ve had storms long enough in Wilmington and this particular area that all power lines should have been underground by now. We know we’re going to get hit.”

Across the nation, severe weather fueled by climate change is pushing aging electrical systems past their limits, often with deadly results. Last year, amid increasing nationwide blackouts, the average American home endured more than eight hours without power, according to the U.S. Energy Information Administration — more than double the outage time five years ago.

This year alone, a wave of abnormally severe winter storms caused a disastrous power failure in Texas, leaving millions of homes in the dark, sometimes for days, and at least 200 dead. Power outages caused by Hurricane Ida contributed to at least 14 deaths in Louisiana, as some of the poorest parts of the state suffered through weeks of 90-degree heat without air conditioning.

As storms grow fiercer and more frequent, environmental groups are pushing states to completely reimagine the electrical grid, incorporating more grid-scale batteries, renewable energy sources and localized systems known as “microgrids,” which they say could reduce the incidence of wide-scale outages. Utility companies have proposed their own storm-proofing measures, including burying power lines underground.

But state regulators largely have rejected these ideas, citing pressure to keep energy rates affordable. Of $15.7 billion in grid improvements under consideration last year, regulators approved only $3.4 billion, according to a national survey by the NC Clean Energy Technology Center — about one-fifth, highlighting persistent vulnerabilities in the grid nationwide.

After a weather disaster, “everybody’s standing around saying, ‘Why didn’t you spend more to keep the lights on?’ ” Ted Thomas, chairman of the Arkansas Public Service Commission, said in an interview with The Washington Post. “But when you try to spend more when the system is working, it’s a tough sell.”

A major impediment is the failure by state regulators and the utility industry to consider the consequences of a more volatile climate — and to come up with better tools to prepare for it. For example, a Berkeley Lab study last year of outages caused by major weather events in six states found that neither state officials nor utility executives attempted to calculate the social and economic costs of longer and more frequent outages, such as food spoilage, business closures, supply chain disruptions and medical problems.

“There is no question that climatic changes are happening that directly affect the operation of the power grid,” said Justin Gundlach, a senior attorney at the Institute for Policy Integrity, a think tank at New York University Law School. “What you still haven’t seen … is a [state] commission saying: 'Isn’t climate the through line in all of this? Let’s examine it in an open-ended way. Let’s figure out where the information takes us and make some decisions.’ ”

In interviews, several state commissioners acknowledged that failure.

“Our electric grid was not built to handle the storms that are coming this next century,” said Tremaine L. Phillips, a commissioner on the Michigan Public Service Commission, which in August held an emergency meeting to discuss the problem of power outages. “We need to come up with a broader set of metrics in order to better understand the success of future improvements.”

Five disasters in four years
The need is especially urgent in North Carolina, where experts warn Atlantic grids and coastlines need a rethink as the state has declared a federal disaster from a hurricane or tropical storm five times in the past four years. Among them was Hurricane Florence, which brought torrential rain, catastrophic flooding and the state’s worst outage in over a decade in September 2018.

More than 1 million residents were left disconnected from refrigerators, air conditioners, ventilators and other essential machines, some for up to two weeks. Elderly residents dependent on oxygen were evacuated from nursing homes. Relief teams flew medical supplies to hospitals cut off by flooded roads. Desperate people facing closed stores and rotting food looted a Wilmington Family Dollar.

“I have PTSD from Hurricane Florence, not because of the actual storm but the aftermath,” said Evelyn Bryant, a community organizer who took part in the Wilmington response.

The storm reignited debate over a $13 billion proposal by Duke Energy, one of the largest power companies in the nation, to reinforce the state’s power grid. A few months earlier, the state had rejected Duke’s request for full repayment of those costs, determining that protecting the grid against weather is a normal part of doing business and not eligible for the type of reimbursement the company had sought.

After Florence, Duke offered a smaller, $2.5 billion plan, along with the argument that severe weather events are one of seven “megatrends” (including cyberthreats and population growth) that require greater investment, according to a PowerPoint presentation included in testimony to the state. The company owns the two largest utilities in North Carolina, Duke Energy Carolinas and Duke Energy Progress.

Vote Solar, a nonprofit climate advocacy group, objected to Duke’s plan, saying the utility had failed to study the risks of climate impacts. Duke’s flood maps, for example, had not been updated to reflect the latest projections for sea level rise, they said. In testimony, Vote Solar claimed Duke was using environmental trends to justify investments “it had already decided to pursue.”

The United States is one of the few countries where regulated utilities are usually guaranteed a rate of return on capital investments, even as studies show the U.S. experiences more blackouts than much of the developed world. That business model incentivizes spending regardless of how well it solves problems for customers and inspires skepticism. Ric O’Connell, executive director of GridLab, a nonprofit group that assists state and regional policymakers on electrical grid issues, said utilities in many states “are waving their hands and saying hurricanes” to justify spending that would do little to improve climate resilience.

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Duke Energy spokesman Jeff Brooks acknowledged that the company had not conducted a climate risk study but pointed out that this type of analysis is still relatively new for the industry. He said Duke’s grid improvement plan “inherently was designed to think about future needs,” including reinforced substations with walls that rise several feet above the previous high watermark for flooding, and partly relied on federal flood maps to determine which stations are at most risk.

Brooks said Duke is not using weather events to justify routine projects, noting that the company had spent more than a year meeting with community stakeholders and using their feedback to make significant changes to its grid improvement plan.

This year, the North Carolina Utilities Commission finally approved a set of grid improvements that will cost customers $1.2 billion. But the commission reserved the right to deny Duke reimbursement of those costs if it cannot prove they are prudent and reasonable. The commission’s general counsel, Sam Watson, declined to discuss the decision, saying the commission can comment on specific cases only in public orders.

The utility is now burying power lines in “several neighborhoods across the state” that are most vulnerable to wide-scale outages, Brooks said. It is also fitting aboveground power lines with “self-healing” technology, a network of sensors that diverts electricity away from equipment failures to minimize the number of customers affected by an outage.

As part of a settlement with Vote Solar, Duke Energy last year agreed to work with state officials and local leaders to further evaluate the potential impacts of climate change, a process that Brooks said is expected to take two to three years.

High costs create hurdles
The debate in North Carolina is being echoed in states across the nation, where burying power lines has emerged as one of the most common proposals for insulating the grid from high winds, fires and flooding. But opponents have balked at the cost, which can run in the millions of dollars per mile.

In California, for example, Pacific Gas & Electric wants to bury 10,000 miles of power lines, both to make the grid more resilient and to reduce the risk of sparking wildfires. Its power equipment has contributed to multiple deadly wildfires in the past decade, including the 2018 Camp Fire that killed at least 85 people.

PG&E’s proposal has drawn scorn from critics, including San Jose Mayor Sam Liccardo, who say it would be too slow and expensive. But Patricia Poppe, the company’s CEO, told reporters that doing nothing would cost California even more in lost lives and property while struggling to keep the lights on during wildfires. The plan has yet to be submitted to the state, but Terrie Prosper, a spokeswoman for the California Public Utilities Commission, said the commission has supported underground lines as a wildfire mitigation strategy.

Another oft-floated solution is microgrids, small electrical systems that provide power to a single neighborhood, university or medical center. Most of the time, they are connected to a larger utility system. But in the event of an outage, microgrids can operate on their own, with the aid of solar energy stored in batteries.

In Florida, regulators recently approved a four-year microgrid pilot project, but the technology remains expensive and unproven. In Maryland, regulators in 2016 rejected a plan to spend about $16 million for two microgrids in Baltimore, in part because the local utility made no attempt to quantify “the tangible benefits to its customer base.”

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In Texas, where officials have largely abandoned state regulation in favor of the free market, the results have been no more encouraging. Without requirements, as exist elsewhere, for building extra capacity for times of high demand or stress, the state was ill-equipped to handle an abnormal deep freeze in February that knocked out power to 4 million customers for days.

Since then, Berkshire Hathaway Energy and Starwood Energy Group each proposed spending $8 billion to build new power plants to provide backup capacity, with guaranteed returns on the investment of 9 percent, but the Texas legislature has not acted on either plan.

New York is one of the few states where regulators have assessed the risks of climate change and pushed utilities to invest in solutions. After 800,000 New Yorkers lost power for 10 days in 2012 in the wake of Hurricane Sandy, state regulators ordered utility giant Con Edison to evaluate the state’s vulnerability to weather events.

The resulting report, which estimated climate risks could cost the company as much as $5.2 billion by 2050, gave ConEd data to inform its investments in storm hardening measures, including new storm walls and submersible equipment in areas at risk of flooding.

Meanwhile, the New York Public Service Commission has aggressively enforced requirements that utility companies keep the lights on during big storms, fining utility providers nearly $190 million for violations including inadequate staffing during Tropical Storm Isaias in 2020.

“At the end of the day, we do not want New Yorkers to be at the mercy of outdated infrastructure,” said Rory M. Christian, who last month was appointed chair of the New York commission.

The price of inaction
In North Carolina, as Duke Energy slowly works to harden the grid, some are pursuing other means of fostering climate-resilient communities.

Beth Schrader, the recovery and resilience director for New Hanover County, which includes Wilmington, said some of the people who went the longest without power after Florence had no vehicles, no access to nearby grocery stores and no means of getting to relief centers set up around the city.

For example, Quanesha Mullins, a 37-year-old mother of three, went eight days without power in her housing project on Wilmington’s east side. Her family got by on food from the Red Cross and walked a mile to charge their phones at McDonald’s. With no air conditioning, they slept with the windows open in a neighborhood with a history of violent crime.

Schrader is working with researchers at the University of North Carolina in Charlotte to estimate the cost of helping people like Mullins. The researchers estimate that it would have cost about $572,000 to provide shelter, meals and emergency food stamp benefits to 100 families for two weeks, said Robert Cox, an engineering professor who researches power systems at UNC-Charlotte.

Such calculations could help spur local governments to do more to help vulnerable communities, for example by providing “resilience outposts” with backup power generators, heating or cooling rooms, Internet access and other resources, Schrader said. But they also are intended to show the costs of failing to shore up the grid.

“The regulators need to be moved along,” Cox said.

In the meantime, Tonye Gray finds herself worrying about what happens when the next storm hits. While Duke Energy says it is burying power lines in the most outage-prone areas, she has yet to see its yellow-vested crews turn up in her neighborhood.

“We feel,” she said, “that we’re at the end of the line.”

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EU Renewable Energy Shift is cutting gas dependence as wind and solar expand, reshaping Europe's power mix, curbing emissions, and pressuring coal use amid a supply crisis and rising natural gas prices.

Key Points

An EU trend where wind and solar growth reduce gas reliance, curb coal, and lower power-sector emissions.

✅ Wind and solar displace gas in EU power mix

✅ Coal use rises as gas prices surge

✅ Emissions fall, but not fast enough for 1.5 C target

The European Union’s renewable energy sources are helping reduce its dependence on natural gas, under the current European electricity pricing framework, that’s still costing the region dearly.

Renewables growth has helped reduce the EU’s dependence on gas, as wind and solar outpaced gas across the bloc last year, which has soared in price since the middle of last year as the region grapples with a supply crisis that’s dealt blows to industries as well as ordinary consumers’ pockets. More than half of new renewable generation since 2019 has replaced gas power, according to a study by London-based climate think tank Ember, with the rest replacing mainly nuclear and coal sources.

“These are moments and paradigm shifts when governments and businesses start taking this much more seriously,” said Charles Moore, the lead author on the study, amid Covid-19 responses accelerating the transition across Europe. “The alternatives are available, they are cheaper, and they are likely to get even cheaper and more competitive. Renewables are now an opportunity, not a cost.”

The high price of gas relative to coal has meant utilities are leaning more on coal as a back-up for renewable generation, as stunted hydro and nuclear output has constrained low-carbon alternatives in parts of Europe, which risks the trajectory of Europe’s phase-out of the dirtiest fossil fuel. Last year, the EU’s coal use jumped disproportionately high relative to the rise in power generation as high gas prices boosted the relative profitability of burning coal instead.

Europe Coal Use Jumps as Costly Gas Turns Firms to Dirty Fuel
EU power generation from renewables reached a record high in 2021 of 547 terawatt-hours last year, accounting for an 11% increase compared to two years before, according to Ember’s Europe Electricity Review. It’s more than doubled in a decade, representing a 157% increase since 2011. 

Gas use declined last year for the second year in a row, as Europe explores storing electricity in gas pipelines to leverage existing infrastructure, reaching a level 8.1% lower than 2019. By contrast, coal use fell just 3.3% in the same period. Put simply, wind and solar did a great job of replacing coal during 2011-2019 but since then renewables have mostly been nudging out gas-fired power stations.

Ember’s Moore warned that the slowing phase-out of coal might require legislation to accelerate. The International Energy Agency recommends OECD countries cease using coal by the end of the decade to ensure alignment with the Paris Agreement target of keeping the world’s temperature increase below 1.5 Celsius, with renewables poised to eclipse coal globally by the mid-2020s lending momentum. 

“Europe can accelerate the phasing out of coal by building more renewable energy and faster,” said Felicia Aminoff,  an energy-transition analyst at BloombergNEF. “Wind and solar have no fuel costs, so as soon as you have made the initial investments to build wind and solar capacity it will start replacing generation that uses any kind of fuel, whether it is coal or gas.”

Overall, EU power sector emissions fell at less than half the rate required to hit that target, Ember’s report said. Spain produced the largest emissions reduction in the last two years, with renewables adding about 25 TWh and gas falling 15 TWh, and in Germany renewables topped coal and nuclear for the first time to support the shift. In contrast, heavy use of coal dragged down the bloc’s climate progress in Poland, where coal use rose about 8 TWh and renewables gained only 4 TWh.

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Ontario Gas Plant Expansion aims to boost grid reliability as nuclear refurbishments proceed, using natural gas to meet electricity demand, despite critics urging renewables, energy storage, and efficiency to reduce carbon emissions, protecting investment growth.

Key Points

Ontario plan to expand gas plants for reliability during nuclear outages, sparking debate on emissions and clean options.

✅ IESO data: gas share rose from 4% (2017) to 10.4% (2022).

✅ Government cites nuclear refurbishments and demand growth.

✅ Critics propose storage, wind, solar, and efficiency.

The Ontario government is preparing to expand gas-fired power plants in Ontario; a move critics say will make the province's electricity system dirtier and could eventually leave taxpayers on the hook.

The province is currently soliciting bids for additional gas-fired electricity generation, which means new gas plants get built, or existing gas plants get expanded. 

It's poised to be Ontario's biggest increase in the gas-fired power supply in more than a decade since the previous Liberal government scrapped two gas plants, in Mississauga and Oakville, at a cost the auditor general pegged at around $1 billion. 

Doug Ford's energy minister, Todd Smith, says Ontario needs gas plants now to help meet an expected surge in demand for electricity as the province faces a supply shortfall in the coming years and to provide power while some units of the province's nuclear stations are down for refurbishment. 

"It's really important to have natural gas as an insurance policy to keep the lights on and provide the reliability that we need," Smith said in an interview. 

"We need natural gas for the short term, especially to get us through these refurbishments."

The portion of Ontario's electricity supply that comes from natural gas matters for the environment and the province's economy. Manufacturing companies increasingly seek clean power that emits as little carbon dioxide as possible. 

The portion of Ontario's electricity supply that comes from natural gas matters for the environment and the province's economy. Manufacturing companies increasingly seek a power supply that emits as little carbon dioxide as possible. 

Increasing the amount of gas-fired generation in the electricity system puts Ontario's ability to attract such investments at risk as it complicates balancing demand and emissions across the grid, says Evan Pivnick, program manager with Clean Energy Canada, a think tank. 

"Building new natural gas (power plants) in Ontario today should be seen as an absolute last resort for meeting our energy needs," said Pivnick in an interview. 

Ontario's electricity system has among the lowest rates of CO2 emissions in North America, with roughly half of the annual supply provided by nuclear power, one-quarter from hydro dams, and one-tenth from wind turbines. 

However, Ontario's gas plants have produced a growing amount of electricity in recent years, despite an early report exploring a gas halt by the minister, and that trend will continue if new gas plants are built. 

In 2017, gas- and oil-fired generation provided just four percent of Ontario's electricity supply, according to figures from the provincial agency that manages the grid, the Independent Electricity System Operator (IESO). 

By 2022, that figure reached 10.4 percent. 

Ontario doesn't need new gas plants to meet the electricity demand, says Bryan Purcell, vice president of policy and programs at The Atmospheric Fund. This agency invests in low-carbon projects in the Greater Toronto and Hamilton Area. 

"We're quite concerned about where Ontario's electric grid is going," said Purcell. "Thankfully, there's still time to adjust course and look at other options." 

According to Purcell and Pivnick, those options to avoid gas could include power storage (in which excess generated energy is stored for later use when electricity demand rises), wind and solar projects, or energy efficiency and conservation programs.

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Ontario-Quebec Electricity Trade Agreement ends as Ontario pivots to IESO procurement, hydropower alternatives, natural gas capacity, and energy auctions, impacting grid reliability, power imports, and GHG emissions across both provincial markets.

Key Points

A seven-year power import pact; Ontario will end it, shifting to IESO procurement and gas capacity.

✅ Seasonal hydropower exchange of 2.3 TWh annually.

✅ IESO projects Quebec supply constraints by decade end.

✅ Ontario adds gas, auctions; near-term sector GHGs rise.

The Ontario government does not plan to renew the Ontario-Quebec electricity trade agreement, Radio-Canada is reporting.

The seven-year contract, which expires next year, aims to reduce Ontario's greenhouse gas (GHG) emissions by buying 2.3 Terawatt-hours of electricity from Quebec annually — that corresponds to about seven per cent of Hydro-Quebec's average annual exports.

The announcement comes as the provincially owned Quebec utility continues its legal battle over a plan to export power to Massachusetts.

The Ontario agreement has guaranteed a seasonal exchange of energy, since Quebec has a power surplus in summer, and the province's electricity needs increase in the winter. Ontario plans on exercising its last and only option in the summer of 2026, for a block of 500 megawatts.

The office of the Ontario Minister of Energy Todd Smith says the province will save money by relying "on a competitive procurement process" instead, amid debates over clean, affordable electricity policy in Ontario. And, the Independent Electricity System Operator (IESO), the equivalent of Hydro-Quebec in Ontario, added that, at any rate, Quebec is expected to "run out of electricity in the middle or at the end of the decade."

During the Quebec election campaign, Premier Francois Legault said his province needed to increase hydroelectricity production because he is expecting demand for hydroelectricity to increase by an additional 100 terawatt-hours in the coming decades — half of Hydro-Quebec's current annual output.

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The provinces will still continue to buy and sell power, reaching deals through annual energy auctions.

Eloise Edom, an associate researcher at Polytechnique Montreal's Institut de l'energie Trottier, says the announcement came as somewhat of a surprise because "we're still talking about a lot of energy."

Hydro-Quebec refused to comment on "the SIERE [Independent Electricity System Operator]'s intentions for the agreement, which ends next year," said company spokesperson Lynn St-Laurent.

No green options
Yet Ontario is running out of electricity, even as questions persist about whether it is embracing clean power to meet demand, in part because of plans to refurbish nuclear reactors at the Bruce and Darlington generator stations.

Windsor has already lost out on a $2.5-billion factory because the region is short of electricity for new industrial loads. And by 2025, Toronto will run out of power for the electrification of its transit system, according to the latest estimates from the IESO.

The Ford government recently announced that it hopes to extend the life of the Pickering nuclear station amid ongoing debate. It is also evaluating the possibility of increasing hydroelectricity production at its existing dams.

For now, Ontario is banking on its natural gas plants to meet demand, which have won most recent IESO tenders for contracts running until 2026. Last Friday, the province announced that it was going to buy an additional 1,500 megawatts by 2027.

"The [Ontario energy] minister's expectations may be that the increase in natural gas prices is temporary and that it will fade," energy economist Jean-Thomas Bernard said. "With this in mind, he probably does not want to sign a long-term contract [with Hydro-Quebec] and prefers to buy electricity on a day-to-day basis and through calls for tenders."

If the Quebec deal expires, Ontario, Canada's second highest GHG emitter, would have to increase its emissions for the sector, at least in the medium term, with electricity getting dirtier as gas fills the gap.

Last year, the IESO found that it would be very difficult to set a moratorium on natural gas before 2030. The IESO must produce a final report on the subject for the energy minister by the end of November.

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California Income-Based Electricity Rates propose a fixed monthly fee set by income as utilities and the CPUC weigh progressive pricing, aiming to cut low-income bills while PG&E, SCE, and SDG&E retain usage-based charges.

Key Points

CPUC plan adds income-tiered fixed fees to lower low-income bills while keeping per-kWh usage charges.

✅ Adds fixed monthly fees by income to complement per-kWh charges

✅ Cuts bills for low-income households; higher earners pay more

✅ Utilities say revenue neutral; conservation signals preserved

California’s electric bills — already some of the highest in the nation — are rising as electricity prices soar across the state, but regulators are debating a new plan to charge customers based on their income level. 

Typically what you pay for electricity depends on how much you use. But the state’s three largest electric utilities — Southern California Edison Company, Pacific Gas and Electric Company and San Diego Gas & Electric Company — have proposed a plan to charge customers not just for how much energy they use, but also based on their household income, moving toward income-based flat-fee utility bills over time. Their proposal is one of several state regulators received designed to accommodate a new law to make energy less costly for California’s lowest-income customers.

Some state Republican lawmakers are warning the changes could produce unintended results, such as weakening incentives to conserve electricity or raising costs for customers using solar energy, and some have introduced a plan to overturn the charges in the Legislature.

But the utility companies say the measure would reduce electricity bills for the lowest income customers. Those residents would save about $300 per year, utilities estimate.

California households earning more than $180,000 a year would end up paying an average of $500 more a year on their electricity bills, according to the proposal from utility companies. 

The California Public Utilities Commission’s deadline for deciding on the suggested changes is July 1, 2024, as regulators face calls for action from consumers and advocates. The proposals come at a time when many moderate and low-income families are being priced out of California by rising housing costs.  

Who wants to change the fee structure?
Lawmakers passed and Gov. Gavin Newsom signed a comprehensive energy bill last summer that mandates restructuring electricity pricing across the state. 

The Legislature passed the measure in a “trailer-bill” process that limited deliberation. Included in the 21,000-word law are a few sentences requiring the public utilities commission to establish a “fixed monthly fee” based on each customer’s household income. 

A similar idea was first proposed in 2021 by researchers at UC Berkeley and the nonprofit thinktank Next 10. Their main recommendation was to split utility costs into two buckets. Fixed charges, which everyone has to pay just to be connected to the energy grid, would be based on income levels. Variable charges would depend on how much electricity you use.

Utilities say that part of customers’ bills still will be based on usage, but the other portion will reduce costs for lower- and middle-income customers, who “pay a greater percentage of their income towards their electricity bill relative to higher income customers,” the utilities argued in a recent filing. 

They said the current billing system is unjust, regressive and fails to recognize differences in energy usage among households,

“When we were putting together the reform proposal, front and center in our mind were customers who live paycheck to paycheck, who struggle to pay for essentials such as energy, housing and food,” Caroline Winn, CEO of San Diego Gas & Electric in a statement. 

The utilities say in their proposal that the changes likely would not reduce or increase their revenues.

James Sallee, an associate professor at UC Berkeley, said the utilities’ prior system of billing customers mostly by measuring their electric use to pay for what are essentially fixed costs for power is inefficient and regressive. 

The proposed changes “will shift the burden, on average, to a more progressive system that recovers more from higher income households and less from lower income households,” he said.

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Asia Electricity Consumption 2025 highlights an IEA forecast of surging global power demand led by China, lagging access in Africa, rising renewables and nuclear output, stable emissions, and weather-dependent grids needing flexibility and electrification.

Key Points

An IEA forecast that Asia will use half of global power by 2025, led by China, as renewables and nuclear drive supply.

✅ Asia to use half of global electricity; China leads growth

✅ Africa just 3% consumption despite rapid population growth

✅ Renewables, nuclear expand; grids must boost flexibility

Asia will for the first time use half of the world’s electricity by 2025, even as global power demand keeps rising and Africa continues to consume far less than its share of the global population, according to a new forecast released Wednesday by the International Energy Agency.

Much of Asia’s electricity use will be in China, a nation of 1.4 billion people whose China's electricity sector is seeing shifts as its share of global consumption will rise from a quarter in 2015 to a third by the middle of this decade, the Paris-based body said.

“China will be consuming more electricity than the European Union, United States and India combined,” said Keisuke Sadamori, the IEA’s director of energy markets and security.

By contrast, Africa — home to almost a fifth of world’s nearly 8 billion inhabitants — will account for just 3% of global electricity consumption in 2025.

“This and the rapidly growing population mean there is still a massive need for increased electrification in Africa,” said Sadamori.

The IEA’s annual report predicts that low-emissions sources will account for much of the growth in global electricity supply over the coming three years, including nuclear power and renewables such as wind and solar. This will prevent a significant rise in greenhouse gas emissions from the power sector, it said.

Scientists say sharp cuts in all sources of emissions are needed as soon as possible to keep average global temperatures from rising 1.5 degrees Celsius (2.7 Fahrenheit) above pre-industrial levels. That target, laid down in the 2015 Paris climate accord, appears increasingly doubtful as temperatures have already increased by more than 1.1 C since the reference period.

One hope for meeting the goal is a wholesale shift away from fossil fuels such as coal, gas and oil toward low-carbon sources of energy. But while some regions are reducing their use of coal and gas for electricity production, in others, soaring electricity and coal use are increasing, the IEA said.

The 134-page also report warned that surging electricity demand and supply are becoming increasingly weather dependent, a problem it urged policymakers to address.

“In addition to drought in Europe, there were heat waves in India (last year),” said Sadamori. “Similarly, central and eastern China were hit by heatwaves and drought. The United States, where electricity sales projections continue to fall, also saw severe winter storms in December, and all those events put massive strain on the power systems of these regions.”

“As the clean energy transition gathers pace, the impact of weather events on electricity demand will intensify due to the increased electrification of heating, while the share of weather-dependent renewables poised to eclipse coal will continue to grow in the generation mix,” the IEA said. “In such a world, increasing the flexibility of power systems while ensuring security of supply and resilience of networks will be crucial.”

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