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Renewables Overtake Coal in the US, as solar, wind, and hydro expand grid share; EIA data show an energy transition accelerated by COVID-19, slashing emissions, displacing fossil fuels, and reshaping electricity generation and climate policy.

Key Points

It refers to the milestone where US renewable energy generation surpassed coal, marking a pivotal energy transition.

✅ EIA data show renewables topped coal consumption in 2019.

✅ Solar, wind, and hydro displaced aging, costly coal plants.

✅ COVID-19 demand drop accelerated the energy transition.

Solar, wind and other renewable sources have toppled coal in energy generation in the United States for the first time in over 130 years, with the coronavirus pandemic accelerating a decline in coal that has profound implications for the climate crisis.

Not since wood was the main source of American energy in the 19th century has a renewable resource been used more heavily than coal, but 2019 saw a historic reversal, building on wind and solar reaching 10% of U.S. generation in 2018, according to US government figures.

Coal consumption fell by 15%, down for the sixth year in a row, while renewables edged up by 1%, even as U.S. electricity use trended lower. This meant renewables surpassed coal for the first time since at least 1885, a year when Mark Twain published The Adventures of Huckleberry Finn and America’s first skyscraper was erected in Chicago.

Electricity generation from coal fell to its lowest level in 42 years in 2019, with the US Energy Information Administration (EIA) forecasting that renewables will eclipse coal as an electricity source this year, while a global eclipse by 2025 is also projected. On 21 May, the year hit its 100th day in which renewables have been used more heavily than coal.

“Coal is on the way out, we are seeing the end of coal,” said Dennis Wamsted, analyst at the Institute for Energy Economics and Financial Analysis. “We aren’t going to see a big resurgence in coal generation, the trend is pretty clear.”

The ongoing collapse of coal would have been nearly unthinkable a decade ago, when the fuel source accounted for nearly half of America’s generated electricity, even as a brief uptick in 2021 was anticipated. That proportion may fall to under 20% this year, with analysts predicting a further halving within the coming decade.

A rapid slump since then has not been reversed despite the efforts of the Trump administration, which has dismantled a key Barack Obama-era climate rule to reduce emissions from coal plants and eased requirements that prevent coal operations discharging mercury into the atmosphere and waste into streams.

Coal releases more planet-warming carbon dioxide than any other energy source, with scientists warning its use must be rapidly phased out to achieve net-zero emissions globally by 2050 and avoid the worst ravages of the climate crisis.

Countries including the UK and Germany are in the process of winding down their coal sectors, and in Europe renewables are increasingly crowding out gas as well, although in the US the industry still enjoys strong political support from Trump.

“It’s a big moment for the market to see renewables overtake coal,” said Ben Nelson, lead coal analyst at Moody’s. “The magnitude of intervention to aid coal has not been sufficient to fundamentally change its trajectory, which is sharply downwards.”

Nelson said he expects coal production to plummet by a quarter this year but stressed that declaring the demise of the industry is “a very tough statement to make” due to ongoing exports of coal and its use in steel-making. There are also rural communities with power purchase agreements with coal plants, meaning these contracts would have to end before coal use was halted.

The coal sector has been beset by a barrage of problems, predominantly from cheap, abundant gas that has displaced it as a go-to energy source. The Covid-19 outbreak has exacerbated this trend, even as global power demand has surged above pre-pandemic levels. With plunging electricity demand following the shutting of factories, offices and retailers, utilities have plenty of spare energy to choose from and coal is routinely the last to be picked because it is more expensive to run than gas, solar, wind or nuclear.

Many US coal plants are ageing and costly to operate, forcing hundreds of closures over the past decade. Just this year, power companies have announced plans to shutter 13 coal plants, including the large Edgewater facility outside Sheboygan, Wisconsin, the Coal Creek Station plant in North Dakota and the Four Corners generating station in New Mexico – one of America’s largest emitters of carbon dioxide.

The last coal facility left in New York state closed earlier this year.

The additional pressure of the pandemic “will likely shutter the US coal industry for good”, said Yuan-Sheng Yu, senior analyst at Lux Research. “It is becoming clear that Covid-19 will lead to a shake-up of the energy landscape and catalyze the energy transition, with investors eyeing new energy sector plays as we emerge from the pandemic.”

Climate campaigners have cheered the decline of coal but in the US the fuel is largely being replaced by gas, which burns more cleanly than coal but still emits a sizable amount of carbon dioxide and methane, a powerful greenhouse gas, in its production, whereas in the EU wind and solar overtook gas last year.

Renewables accounted for 11% of total US energy consumption last year – a share that will have to radically expand if dangerous climate change is to be avoided. Petroleum made up 37% of the total, followed by gas at 32%. Renewables marginally edged out coal, while nuclear stood at 8%.

“Getting past coal is a big first hurdle but the next round will be the gas industry,” said Wamsted. “There are emissions from gas plants and they are significant. It’s certainly not over.”
 

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WA $600 Electricity Credit supports households with power bills as a budget stimulus, delivering an automatic rebate via Synergy and Horizon, funded by the Bell Group settlement to aid COVID-19 recovery and local spending.

Key Points

A one-off $600 power bill credit for all Synergy and Horizon residential accounts, funded by the Bell Group settlement.

✅ Automatic, not means-tested; applied to Synergy and Horizon accounts.

✅ Can offset upcoming bills or carry forward to future statements.

✅ Funded by Bell Group payout; aims to ease cost-of-living pressures.

Washington Premier Mark McGowan has announced more than a million households will receive a $600 electricity credit on their electricity account before their next bill.

The $650 million measure will form part of Thursday's pre-election state budget, similar to legislation to lower electricity rates in other jurisdictions, which has been delayed since May because of the pandemic and will help deflect criticism by the opposition that Labor hasn't done enough to stimulate WA's economy.

Mr McGowan made the announcement on Sunday while visiting a family in the electorate of Bicton.

"Here in WA, our state is in the best possible position as we continue our strong recovery from COVID-19, but times are still tough for many West Australians, and there is always more work to do," he said.

"[The credit] will mean WA families have a bit of extra money available in the lead up to Christmas.

"But I have a request, if this credit means you can spend some extra money, use it to support our local WA businesses."

The electricity bill credit will be automatically applied to every Synergy or Horizon residential account from Sunday, echoing moves such as reconnections for nonpayment by Hydro One in Canada.

It can be applied to future bills and will not be means tested.

"The $600 credit is fully funded through the recent Bell Group settlement, for the losses incurred in the Bell Group collapse in the early 1990s," Mr McGowan said.

"It made sense that these funds go straight back to Western Australians."

In September, the liquidator for the Bell Group and its finance arm distributed funds to its five major creditors, including $670 million to the WA government. The payment marked the close of the 30-year battle to recover taxpayer funds squandered during the WA Inc era of state politics.

The payout is the result of litigation stemming from the 1988 partnership between then Labor government and entrepreneur Alan Bond in acquiring major interests in Robert Holmes à Court’s failing Bell Group, following the 1987 stock market crash.

WA shadow minister for cost of living, Tony Krsticevic, said the $600 credit was returning money back into West Australian's pockets from "WA Labor's darkest days".

“This is taxpayers’ money out of a levy which was brought in to pay for Labor’s scandalous WA Inc losses of $450 million in the 1980s,” he said.

“This money should be returned to West Australians.

“WA families are in desperate need of it because they are struggling under cost of living increases of $850 every year since 2017 under WA Labor, amid concerns elsewhere that an electricity recovery rate could lead to higher hydro bills.

“But they need more than just a one-off payment. These $850 cost of living increases are an on-going burden.”

Prior to the onset of the coronavirus pandemic, the opposition believed it was gaining traction by attacking the government's increases to fees and charges in its first three budgets, and by urging an electricity market overhaul to favor consumers.

Last year, Labor increased household fees and charges by $127.77, which came on top of increases over the prior two budgets, as other jurisdictions faced hydro rate increases of around 3 per cent.

According the state's annual report on its finances released in September, the $2.6 billion budget surplus forecast in the at the end of 2019 had been reduced by $920 million to $1.7 billion despite the impact of the coronavirus.

But total public sector net debt was at $35.4 billion, down from the $36.1 billion revision at the end of 2019 in the mid-year review.

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Eletrobras Privatization Strike sparks a 72-hour CNE walkout by Brazil's electricity workers, opposing asset sell-offs and grid privatization while pledging essential services; unions target President Wilson Ferreira Jr. over energy-sector reforms.

Key Points

A 72-hour CNE walkout by Brazil's electricity workers opposing Eletrobras sell-offs, while keeping essential services.

✅ 72-hour strike led by CNE unions and federations

✅ Targets privatization plans and leadership at Eletrobras

✅ Essential services maintained to avoid consumer impact

Brazil's national electricity workers' collective (CNE) has called for a 72-hour strike to protest the privatization of state-run electric company Eletrobras and its subsidiaries.

The CNE, which gathers the electricity workers' confederation, federations, unions and associations, said the strike is to begin at Monday midnight (0300 GMT) and last through midnight Wednesday, even as some utilities elsewhere have considered asking staff to live on site to maintain operations.

Workers are demanding the ouster of Eletrobras President Wilson Ferreira Jr., who they say is the leading promoter of the privatization move.

Some 24,000 workers are expected to take part in the strike. However, the CNE said it will not affect consumers by ensuring essential services, a pledge echoed by utilities managing costs elsewhere such as Manitoba Hydro's unpaid days off during the pandemic.

#google#

Eletrobras accounts for 32 percent of Brazil's installed energy generation capacity, mainly via hydroelectric plants. Besides, it also operates nuclear and thermonuclear plants, and solar and wind farms, reflecting trends captured by young Canadians' interest in electricity jobs in recent years.

The company distributes electricity in six northern and northeastern states, and handles 47 percent of the nation's electricity transmission lines, even as a U.S. grid pandemic warning has highlighted reliability risks.

The government owns a 63-percent stake in the company, a reminder that public policy shapes the sector, similar to Canada's future-of-work investment initiatives announced recently.

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Methane Hydrate CO2 Sequestration uses carbon capture and nitrogen injection to swap gases in seafloor hydrates along the Gulf of Mexico, releasing methane for electricity while storing CO2, according to new simulation research.

Key Points

A method injecting CO2 and nitrogen into hydrates to store CO2 while releasing methane for power.

✅ Nitrogen aids CO2-methane swap in hydrate cages, speeding sequestration

✅ Gulf Coast proximity to emitters lowers transport and power costs

✅ Revenue from methane electricity could offset carbon capture

The world is quickly realizing it may need to actively pull carbon dioxide out of the atmosphere to stave off the ill effects of climate change. Scientists and engineers have proposed various carbon capture techniques, but most would be extremely expensive—without generating any revenue. No one wants to foot the bill.

One method explored in the past decade might now be a step closer to becoming practical, as a result of a new computer simulation study. The process would involve pumping airborne CO2 down into methane hydrates—large deposits of icy water and methane right under the seafloor, beneath water 500 to 1,000 feet deep—where the gas would be permanently stored, or sequestered. The incoming CO2 would push out the methane, which would be piped to the surface and burned to generate electricity, whether sold locally or via exporters like Hydro-Que9bec to help defray costs, to power the sequestration operation or to bring in revenue to pay for it.

Many methane hydrate deposits exist along the Gulf of Mexico shore and other coastlines. Large power plants and industrial facilities that emit CO2 also line the Gulf Coast, where EPA power plant rules could shape deployment, so one option would be to capture the gas directly from nearby smokestacks, keeping it out of the atmosphere to begin with. And the plants and industries themselves could provide a ready market for the electricity generated.

A methane hydrate is a deposit of frozen, latticelike water molecules. The loose network has many empty, molecular-size pores, or “cages,” that can trap methane molecules rising through cracks in the rock below. The computer simulation shows that pushing out the methane with CO2 is greatly enhanced if a high concentration of nitrogen is also injected, and that the gas swap is a two-step process. (Nitrogen is readily available anywhere, because it makes up 78 percent of the earth’s atmosphere.) In one step the nitrogen enters the cages; this destabilizes the trapped methane, which escapes the cages. In a separate step, the nitrogen helps CO2 crystallize in the emptied cages. The disturbed system “tries to reach a new equilibrium; the balance goes to more CO2 and less methane,” says Kris Darnell, who led the study, published June 27 in the journal Water Resources Research. Darnell recently joined the petroleum engineering software company Novi Labs as a data scientist, after receiving his Ph.D. in geoscience from the University of Texas, where the study was done.

A group of labs, universities and companies had tested the technique in a limited feasibility trial in 2012 on Alaska’s North Slope, where methane hydrates form in sandstone under deep permafrost. They sent CO2 and nitrogen down a pipe into the hydrate. Some CO2 ended up being stored, and some methane was released up the same pipe. That is as far as the experiment was intended to go. “It’s good that Kris [Darnell] could make headway” from that experience, says Ray Boswell at the U.S. Department of Energy’s National Energy Technology Laboratory, who was one of the Alaska experiment leaders but was not involved in the new study. The new simulation also showed that the swap of CO2 for methane is likely to be much more extensive—and to happen quicker—if CO2 enters at one end of a hydrate deposit and methane is collected at a distant end.

The technique is somewhat similar in concept to one investigated in the early 2010s by Steven Bryant and others at the University of Texas. In addition to numerous methane hydrate deposits, the Gulf Coast has large pools of hot, salty brine in sedimentary rock under the coastline. In this system, pumps would send CO2 down into one end of a deposit, which would force brine into a pipe that is placed at the other end and leads back to the surface. There the hot brine would flow through a heat exchanger, where heat could be extracted and used for industrial processes or to generate electricity, supporting projects such as electrified LNG in some markets. The upwelling brine also contains some methane that could be siphoned off and burned. The CO2 dissolves into the underground brine, becomes dense and sinks further belowground, where it theoretically remains.

Either system faces big practical challenges, and building shared CO2 storage hubs to aggregate captured gas is still evolving. One is creating a concentrated flow of CO2; the gas makes up only .04 percent of air, and roughly 10 percent of the smokestack emission from a typical power plant or industrial facility. If an efficient methane hydrate or brine system requires an input that is 90 percent CO2, for example, concentrating the gas will require an enormous amount of energy—making the process very expensive. “But if you only need a 50 percent concentration, that could be more attractive,” says Bryant, who is now a professor of chemical and petroleum engineering at the University of Calgary. “You have to reduce the [CO2] capture cost.”

Another major challenge for the methane hydrate approach is how to collect the freed methane, which could simply seep out of the deposit through numerous cracks and in all directions. “What kind of well [and pipe] structure would you use to grab it?” Bryant asks.

Given these realities, there is little economic incentive today to use methane hydrates for sequestering CO2. But as concentrations rise in the atmosphere and the planet warms further, and as calls for an electric planet intensify, systems that could capture the gas and also provide energy or revenue to run the process might become more viable than techniques that simply pull CO2 from the air and lock it away, offering nothing in return.

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Zaporizhzhia Nuclear Plant Mines reported by IAEA at the Russian-occupied site: anti-personnel devices in a buffer zone, restricted areas; access limits to reactor rooftops and turbine halls heighten nuclear safety and security concerns in Ukraine.

Key Points

IAEA reports anti-personnel mines at Russian-held Zaporizhzhia, raising nuclear safety risks in buffer zones.

✅ IAEA observes mines in buffer zone at occupied site

✅ Restricted areas; no roof or turbine hall access granted

✅ Safety systems unaffected, but staff under pressure

The United Nations atomic watchdog said it saw anti-personnel mines at the site of Ukraine's Zaporizhzhia nuclear power plant which is occupied by Russian forces.

Europe's largest nuclear facility fell to Russian forces shortly after the invasion of Ukraine in February last year, as Moscow later sought to build power lines to reactivate it amid ongoing control of the area. Kyiv and Moscow have since accused each other of planning an incident at the site.

On July 23 International Atomic Energy Agency (IAEA) experts "saw some mines located in a buffer zone between the site's internal and external perimeter barriers," agency chief Rafael Grossi said in a statement on Monday.

The statement did not say how many mines the team had seen.

The devices were in "restricted areas" that operating plant personnel cannot access, Mr Grossi said, adding the IAEA's initial assessment was that any detonation "should not affect the site's nuclear safety and security systems".

Laying explosives at the site was "inconsistent with the IAEA safety standards and nuclear security guidance" and, amid controversial proposals on Ukraine's nuclear plants that have circulated internationally, created additional psychological pressure on staff, he added.

Ukrainians in Nikopol are out of water and within Russia's firing line. But Zaporizhzhia nuclear power plant could pose the biggest threat, even as Ukraine has resumed electricity exports to regional grids.

Last week the IAEA said its experts had carried out inspections at the plant, without "observing" the presence of any mines, although they had not been given access to the rooftops of the reactor buildings, while a possible agreement to curb attacks on plants was being discussed.

The IAEA had still not been given access to the roofs of the reactor buildings and their turbine halls, its latest statement said, even as a proposal to control Ukraine's nuclear plants drew scrutiny.

After falling into Russian hands, Europe's biggest power plant was targeted by gunfire and has been severed from the grid several times, raising nuclear risk warnings from the IAEA and others.

The six reactor units, which before the war produced around a fifth of Ukraine's electricity, have been shut down for months, prompting interest in wind power development as a harder-to-disrupt source.

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Canada Power Grid Climate Resilience integrates extreme weather planning, microgrids, battery storage, renewable energy, vegetation management, and undergrounding to reduce outages, harden infrastructure, modernize utilities, and safeguard reliability during storms, ice events, and wildfires.

Key Points

Canada's grid resilience hardens utilities against extreme weather using microgrids, storage, renewables, and upgrades.

✅ Grid hardening: microgrids, storage, renewable integration

✅ Vegetation management reduces storm-related line contact

✅ Selective undergrounding where risk and cost justify

The increasing intensity of storms that lead to massive power outages highlights the need for Canada’s electrical utilities to be more robust and innovative, climate change scientists say.

“We need to plan to be more resilient in the face of the increasing chances of these events occurring,” University of New Brunswick climate change scientist Louise Comeau said in a recent interview.

The East Coast was walloped this week by the third storm in as many days, with high winds toppling trees and even part of a Halifax church steeple, underscoring the value of storm-season electrical safety tips for residents.

Significant weather events have consistently increased over the last five years, according to the Canadian Electricity Association (CEA), which has tracked such events since 2003.

#google#

Nearly a quarter of total outage hours nationally in 2016 – 22 per cent – were caused by two ice storms, a lightning storm, and the Fort McMurray fires, which the CEA said may or may not be classified as a climate event.

“It (climate change) is putting quite a lot of pressure on electricity companies coast to coast to coast to improve their processes and look for ways to strengthen their systems in the face of this evolving threat,” said Devin McCarthy, vice president of public affairs and U.S. policy for the CEA, which represents 40 utilities serving 14 million customers.

The 2016 figures – the most recent available – indicate the average Canadian customer experienced 3.1 outages and 5.66 hours of outage time.

McCarthy said electricity companies can’t just build their systems to withstand the worst storm they’d dealt with over the previous 30 years. They must prepare for worse, and address risks highlighted by Site C dam stability concerns as part of long-term planning.

“There needs to be a more forward looking approach, climate science led, that looks at what do we expect our system to be up against in the next 20, 30 or 50 years,” he said.

Toronto Hydro is either looking at or installing equipment with extreme weather in mind, Elias Lyberogiannis, the utility’s general manager of engineering, said in an email.

That includes stainless steel transformers that are more resistant to corrosion, and breakaway links for overhead service connections, which allow service wires to safely disconnect from poles and prevents damage to service masts.

Comeau said smaller grids, tied to electrical systems operated by larger utilities, often utilize renewable energy sources such as solar and wind as well as battery storage technology to power collections of buildings, homes, schools and hospitals.

“Capacity to do that means we are less vulnerable when the central systems break down,” Comeau said.

Nova Scotia Power recently announced an “intelligent feeder” pilot project, which involves the installation of Tesla Powerwall storage batteries in 10 homes in Elmsdale, N.S., and a large grid-sized battery at the local substation. The batteries are connected to an electrical line powered in part by nearby wind turbines.

The idea is to test the capability of providing customers with back-up power, while collecting data that will be useful for planning future energy needs.

Tony O’Hara, NB Power’s vice-president of engineering, said the utility, which recently sounded an alarm on copper theft, was in the late planning stages of a micro-grid for the western part of the province, and is also studying the use of large battery storage banks.

“Those things are coming, that will be an evolution over time for sure,” said O’Hara.

Some solutions may be simpler. Smaller utilities, like Nova Scotia Power, are focusing on strengthening overhead systems, mainly through vegetation management, while in Ontario, Hydro One and Alectra are making major investments to strengthen infrastructure in the Hamilton area.

“The number one cause of outages during storms, particularly those with high winds and heavy snow, is trees making contact with power lines,” said N.S. Power’s Tiffany Chase.

The company has an annual budget of $20 million for tree trimming and removal.

“But the reality is with overhead infrastructure, trees are going to cause damage no matter how robust the infrastructure is,” said Matt Drover, the utility’s director for regional operations.

“We are looking at things like battery storage and a variety of other reliability programs to help with that.”

NB Power also has an increased emphasis on tree trimming and removal, and now spends $14 million a year on it, up from $6 million prior to 2014.

O’Hara said the vegetation program has helped drive the average duration of power outages down since 2014 from about three hours to two hours and 45 minutes.

Some power cables are buried in both Nova Scotia and New Brunswick, mostly in urban areas. But both utilities maintain it’s too expensive to bury entire systems – estimated at $1 million per kilometre by Nova Scotia Power.

The issue of burying more lines was top of mind in Toronto following a 2013 ice storm, but that’s city’s utility also rejected the idea of a large-scale underground system as too expensive – estimating the cost at around $15 billion, while Ontario customers have seen Hydro One delivery rates rise in recent adjustments.

“Having said that, it is prudent to do so for some installations depending on site specific conditions and the risks that exist,” Lyberogiannis said.

Comeau said lowering risks will both save money and disruption to people’s lives.

“We can’t just do what we used to do,” said Xuebin Zhang, a senior climate change scientist at Environment and Climate Change Canada.

“We have to build in management risk … this has to be a new norm.”

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