China's output of solar cells jumps to 44% of world total

Ireland Coal-Free Electricity Record: EirGrid reports 25 days without coal on the all-island grid, as wind power, renewables, and natural gas dominated generation, cutting CO2 emissions, with Moneypoint sidelined by market competitiveness.

Key Points

It is a 25-day period when the grid used no coal, relying on gas and renewables to reduce CO2 emissions.

✅ 25 days coal-free between April 11 and May 7

✅ Gas 60%, renewables 30% of generation mix

✅ Eurostat: 6.8% drop in Ireland's CO2 emissions

The island of Ireland has gone a record length of time without using coal-fired electricity generation on its power system, Britain's week-long coal-free run providing a recent comparator, Eirgrid has confirmed.

The all-island grid operated without coal between April 11th and May 7th – a total of 25 days, it confirmed. This is the longest period of time the grid has operated without coal since the all-island electricity market was introduced in 2007, echoing Britain's record coal-free stretch seen recently.

Ireland’s largest generating station, Moneypoint in Co Clare, uses coal, with recent price spikes in Ireland fueling concerns about dispatchable capacity, as do some of the larger generation sites in Northern Ireland.

The analysis coincides with the European statistics agency, Eurostat publishing figures showing annual CO2 emissions in Ireland fell by 6.8 per cent last year; partly due to technical problems at Moneypoint.

Over the 25-day period, gas made up 60 per cent of the fuel mix, while renewable energy, mainly wind, accounted for 30 per cent, echoing UK wind surpassing coal in 2016 across the market. Coal-fired generation was available during this period but was not as competitive as other methods.

EirGrid group chief executive Mark Foley said this was “a really positive development” as coal was the most carbon intense of all electricity sources, with its share hitting record lows in the UK in recent years.

“We are acutely aware of the challenges facing the island in terms of meeting our greenhouse gas emission targets, mindful that low-carbon generation stalled in the UK in 2019, through the deployment of more renewable energy on the grid,” he added.

Last year 33 per cent of the island’s electricity came from renewable energy sources, German renewables surpassing coal and nuclear offering a parallel milestone, a new record. Coal accounted for 9 per cent of electricity generation, down from 12.9 per cent in 2017.

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B.C. LNG Electrification embeds clean hydro and wind power into low-emission liquefied natural gas, cutting carbon intensity, enabling coal displacement in Asia, and opening grid-scale demand for independent power producers and ITMO-based climate accounting.

Key Points

Powering LNG with clean electricity cuts carbon intensity, displaces coal, and grows demand for B.C.'s clean power.

✅ Electric-drive LNG cuts emissions intensity by up to 80%.

✅ Creates major grid load, boosting B.C. independent power producers.

✅ Enables ITMO crediting when coal displacement is verified.

B.C. has abundant clean power – if only there was a way to ship those electrons across the sea to help coal-dependent countries reduce their emissions, and even regionally, Alberta–B.C. grid link benefits could help move surplus power domestically.

Natural gas that is liquefied using clean hydro and wind power and then exported would be, in a sense, a way of embedding B.C.’s low emission electricity in another form of energy, and, alongside the Canada–Germany clean energy pact, part of a broader export strategy.

Given the increased demand that could come from an LNG industry – especially one that moves towards greater electrification and, as the IEA net-zero electricity report notes, broader system demand – poses some potentially big opportunities for B.C.’s clean energy independent power sector, as those attending the Clean Energy Association of BC's annual at the Generate conference heard recently.

At a session on LNG electrification, delegates were told that LNG produced in B.C. with electricity could have some significant environmental benefits.

Given how much power an LNG plant that uses electric drive consumes, an electrified LNG industry could also pose some significant opportunities for independent power producers – a sector that had the wind taken out of its sails with the sanctioning of the Site C dam project.

Only one LNG plant being built in B.C. – Woodfibre LNG – will use electric drive to produce LNG, although the companies behind Kitimat LNG have changed their original design plans, and now plan to use electric drive drive as well.

Even small LNG plants that use electric drive require a lot of power.

“We’re talking about a lot of power, since it’s one of the biggest consumers you can connect to a grid,” said Sven Demmig, head of project development for Siemens.

Most LNG plants still burn natural gas to drive the liquefaction process – a choice that intersects with climate policy and electricity grids in Canada. They typically generate 0.35 tonnes of CO2e per tonne of LNG produced.

Because it will use electric drive, LNG produced by Woodfibre LNG will have an emissions intensity that is 80% less than LNG produced in the Gulf of Mexico, said Woodfibre president David Keane.

In B.C., the benchmark for GHG intensities for LNG plants has been set at 0.16 tonnes of CO2e per tonne of LNG. Above that, LNG producers would need to pay higher carbon taxes than those that are below the benchmark.

The LNG Canada plant has an intensity of 0.15 tonnes og CO2e per tonne of LNG. Woodfibre LNG will have an emissions intensity of just 0.059, thanks to electric drive.

“So we will be significantly less than any operating facility in the world,” Keane said.

Keane said Sinopec has recently estimated that it expects China’s demand for natural gas to grow by 82% by 2030.

“So China will, in fact, get its gas supply,” Keane said. “The question is: where will that supply come from?

“For every tonne of LNG that’s being produced today in the United States -- and tonne of LNG that we’re not producing in Canada -- we’re seeing about 10 million tonnes of carbon leakage every single year.”

The first Canadian company to produce LNG that ended up in China is FortisBC. Small independent operators have been buying LNG from FortisBC’s Tilbury Island plant and shipping to China in ISO containers on container ships.

David Bennett, director of communications for FortisBC, said those shipments are traced to industries in China that are, indeed, using LNG instead of coal power now.

“We know where those shipping containers are going,” he said. “They’re actually going to displace coal in factories in China.”

Verifying what the LNG is used for is important, if Canadian producers want to claim any kind of climate credit. LNG shipped to Japan or South Korea to displace nuclear power, for example, would actually result in a net increase in GHGs. But used to displace coal, the emissions reductions can be significant, since natural gas produces about half the CO2 that coal does.

The problem for LNG producers here is B.C.’s emissions reduction targets as they stand today. Even LNG produced with electricity will produce some GHGs. The fact that LNG that could dramatically reduce GHGs in other countries, if it displaces coal power, does not count in B.C.’s carbon accounting.

Under the Paris Agreement, countries agree to set their own reduction targets, and, for Canada, cleaning up Canada’s electricity remains critical to meeting climate pledges, but don’t typically get to claim any reductions that might result outside their own country.

Canada is exploring the use of Internationally Transferred Mitigation Outcomes (ITMO) under the Under the Paris Agreement to allow Canada to claim some of the GHG reductions that result in other countries, like China, through the export of Canadian LNG.

“For example, if I were producing 4 million tonnes of greenhouse gas emissions in B.C. and I was selling 100% of my LNG to China, and I can verify that they’re replacing coal…they would have a reduction of about 60 or million tonnes of greenhouse gas emissions,” Keane said.

“So if they’re buying 4 million tonnes of emissions from us, under these ITMOs, then they have net reduction of 56 million tonnes, we’d have a net increase of zero.”

But even if China and Canada agreed to such a trading arrangement, the United Nations still hasn’t decided just how the rules around ITMOs will work.

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Municipal Renewable Energy Procurement surged as cities contracted 3.7 GW of solar and wind, leveraging green tariffs, community solar, and utility partnerships across the Southeast, led by Houston, RMI, and WRI data.

Key Points

The process by which cities contract solar and wind via utilities or green tariffs to meet climate goals.

✅ 3.7 GW procured in 2020, nearly 25% year-over-year growth

✅ Houston runs city ops on 500 MW solar, a record purchase

✅ Southeast cities use green tariffs and community solar

Cities around the country bought more renewable energy last year than ever before, reflecting how renewables may soon provide one-fourth of U.S. electricity across the grid, with some of the most remarkable projects in the Southeast, according to new data unveiled Thursday.

Even amid the pandemic, about eight dozen municipalities contracted to buy nearly 3.7 gigawatts of mostly solar and wind energy — enough to power more than 800,000 homes. The figure is almost a quarter higher than the year before.

Half of the cites listed as “most noteworthy” in Thursday’s release —  from research groups Rocky Mountain Institute and World Resources Institute — are in the region that stretches from Texas to Washington, D.C. 

Houston stands out for the sheer enormity of its purchase: In July, it began powering city operations entirely from nearly 500 megawatts of solar power — the largest municipal purchase of renewable energy ever in the United States, as renewable electricity surpassed coal nationwide.

The groups also feature smaller deals in North Carolina and Tennessee, achieved through a utility partnership called a green tariff.

“We wanted to recognize that Nashville and Charlotte were really blazing a new trail,” said Stephen Abbott, principal at the Rocky Mountain Institute.

And the nation’s capital shows how renewable energy can be a source of revenue: It’s leasing out its public transit station rooftops for 10 megawatts of community solar.

All of these strategies will be necessary for scores of U.S. cities to meet their ambitious climate goals, researchers believe. An interactive clean energy targets tracker shows all 95 clean energy procurements from the year in detail.

Tracker 
Even before former President Donald Trump promised to remove the United States from the Paris Climate Accord, a lack of federal action on climate left a void that some cities and counties were beginning to fill, as renewables hit a record 28% in a recent month. In 2015, the first year tracked by researchers at the Rocky Mountain Institute and the World Resources Institute, municipalities contracted to buy more than 1 gigawatt of wind, solar and other forms of clean energy. 

But when Trump officially set in motion the withdrawal from the climate agreement, the ranks of municipalities dedicated to 100% clean energy multiplied. Today there are nearly 200 of them. The growth in activity last year reflects, in part, that surge of new pledges.

“It takes a while to get city staff up to speed and understand the options, and create the roadmap and then start executing,” Abbott said. “There is a bit of a lag, but we’re starting to see the impact.”

Even in Houston — one of the earliest to begin procuring renewable energy — there has been a steep learning curve as market forces change and prices drop, including cheaper solar batteries shaping procurement strategies, said Lara Cottingham, Houston’s chief of staff and chief sustainability officer.

No matter how well resourced and educated their staff, cities have to clear a thicket of structural, political and economic challenges to procure renewable energy. Most don’t own their own sources of power. Nearly all face budget constraints. Few have enough land or government rooftops to meet their goals within city limits.

“Cities face a situation where it’s a square peg in a round hole,” Cottingham said.

The hurdles are especially steep in much of the Southeast, where only publicly regulated utilities can sell electricity to retail customers, even large ones such as major cities. That’s where a green tariff regime comes in: Cities can purchase clean energy from a third party, such as a solar company, using the utility as a go-between.

Early last year, Charlotte became the largest city to use such a program, partnering with Duke Energy and two North Carolina solar developers to build a solar farm 50 miles north in Iredell County. At first, the city will pay a premium for the energy, but in the latter half of the 20-year contract, as gas prices rise, it will save money compared to business as usual.

“Over the course of 20 years, it’s projected we would save about $2 million,” Katie Riddle, sustainability analyst with Charlotte, told the Energy News Network last year.

The growing size of projects, innovative partnerships like green tariff programs, and the improving economics all give Abbott hope that renewable energy investments from cities will only grow — even with the Trump presidency over and the country back in the Paris agreement.

And when cities meet their goals for procuring renewable energy for their own operations, they must then turn to an even bigger task: reducing the carbon footprint of every person in their jurisdiction with broader decarbonization strategies and community engagement.

“The city needs to do its part for sure,” said Houston’s Cottingham. “Then we have this challenge of how do we get everyone else to.”

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US Electricity Generation H1 2018 saw wind and solar gains but hydro declines, as natural gas led the grid mix and coal fell; renewables' share, GWh, emissions, and capacity additions shaped the power sector.

Key Points

It is the H1 2018 US power mix, where natural gas led, coal declined, and wind and solar grew while hydro fell.

✅ Natural gas reached 32% of generation, highest share

✅ Coal fell; renewables roughly tied nuclear at ~20%

✅ Wind and solar up; hydro output down vs 2017

To complement our revival of US electricity capacity reports, here’s a revival of our reports on US electricity generation.

As with the fresh new capacity report, things are not looking too bright when it comes to electricity generation. There’s still a lot of grey — in the bar charts below, in the skies near fossil fuel power plants, and in the human and planetary outlook based on how slowly we are cutting fossil fuel electricity generation.

As you can see in the charts above, wind and solar energy generation increased notably from the first half of 2017 to the first half of 2018, and the EIA expected larger summer solar and wind generation in subsequent months, reinforcing that momentum.

A large positive when it comes to the environment and human health is that coal generation dropped a great deal year over year — by even more than renewables increased, though the EIA later noted an increase in coal-fired generation in a subsequent year, complicating the trend. However, on the down side, natural gas soared as it became the #1 source of electricity generation in the United States (32% of US electricity). Furthermore, coal was still solidly in the #2 position (27% of US electricity). Renewables and nuclear were essentially in a tie at 19.8% of generation, with renewables just a tad above nuclear.

Actually, combined with an increase in nuclear power generation, natural gas electricity production increased so much that the renewable energy share of electricity generation actually dropped in the first half of 2018 versus the first half of 2017, even amid declining electricity use in some periods. It was 19.8% this year and 20% last year.

Again, solar and wind saw a significant growth in its market share, from 9% to 9.9%, but hydro brought the whole category down due to a decrease from 9% to 8%.

The visuals above are probably the best way to examine it all. The H1 2018 chart was still dominated by fossil fuels, which together accounted for approximately 60% of electricity generation, even though by 2021 non-fossil sources supplied about 40% of U.S. electricity, highlighting the longer-term shift. In H1 2017, the figure was 59.7%. Furthermore, if you switch to the “Change H1 2018 vs H1 2017 (GWh)” chart, you can watch a giant grey bar representing natural gas take over the top of the chart. It almost looks like it’s part of the border of the chart. The biggest glimmer of positivity in that chart is seeing the decline in coal at the bottom.

What will the second half of the year bring? Well, the gigantic US electricity generation market shifts slowly, even as monthly figures can swing, as January generation jumped 9.3% year over year according to the EIA, reminding us about volatility. There is so much base capacity, and power plants last so long, that it takes a special kind of magic to create a rapid transition to renewable energy. As you know from reading this quarter’s US renewable energy capacity report, only 43% of new US power capacity in the first half of the year was from renewables. The majority of it was from natural gas. Along with other portions of the calculation, that means that electricity generation from natural gas is likely to increase more than electricity generation from renewables.

Jump into the numbers below and let us know if you have any more thoughts.

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BC Utilities Commission Site C Dam Questions press BC Hydro on geotechnical risks, stability issues, cost overruns, oversight gaps, seeking transparency for ratepayers and clarity on contracts, mitigation, and the powerhouse and spillway foundations.

Key Points

Inquiry seeking explanations from BC Hydro on geotechnical risks, costs, timelines and oversight for Site C.

✅ Timeline of studies, monitoring, and mitigation actions

✅ Rationale for contracts, costs, and right bank construction

✅ Implications for ratepayers, oversight, and project stability

The watchdog B.C. Utilities Commission has sent BC Hydro 70 questions about the troubled Site C dam, asking when geotechnical risks were first identified and when the project’s assurance board was first made aware of potential issues related to the dam’s stability. 

“I think they’ve come to the conclusion — but they don’t say it — that there’s been a cover-up by BC Hydro and by the government of British Columbia,” former BC Hydro CEO Marc Eliesen told The Narwhal. 

On Oct. 21, The Narwhal reported that two top B.C. civil servants, including the senior bureaucrat who prepares Site C dam documents for cabinet, knew in May 2019 that the project faced serious geotechnical problems due to its “weak foundation” and the stability of the dam was “a significant risk.” 

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“They [the civil servants] would have reported to their ministers and to the government in general,” said Eliesen, who is among 18 prominent Canadians calling for a halt to Site C work until an independent team of experts can determine if the geotechnical problems can be resolved and at what cost.  

“It’s disingenuous for Premier [John] Horgan to try to suggest, ‘Well, I just found out about it recently.’ If that’s the case, he should fire the public servants who are representing the province.” 

The public only found out about significant issues with the Site C dam at the end of July, when BC Hydro released overdue reports saying the project faces unknown cost overruns, schedule delays and, even as it achieved a transmission line milestone earlier, such profound geotechnical troubles that its overall health is classified as ‘red,’ meaning it is in serious trouble. 

“The geotechnical challenges have been there all these years.”

The Site C dam is the largest publicly funded infrastructure project in B.C.’s history. If completed, it will flood 128 kilometres of the Peace River and its tributaries, forcing families from their homes and destroying Indigenous gravesites, hundreds of protected archeological sites, some of Canada’s best farmland and habitat for more than 100 species vulnerable to extinction.

Eliesen said geotechnical risks were a key reason BC Hydro’s board of directors rejected the project in the early 1990s, when he was at the helm of BC Hydro.

“The geotechnical challenges have been there all these years,” said Eliesen, who is also the former Chair and CEO of Ontario Hydro, where Ontario First Nations have urged intervention on a critical electricity line, the former Chair of Manitoba Hydro and the former Chair and CEO of the Manitoba Energy Authority.

Elsewhere, a Manitoba Hydro line to Minnesota has faced potential delays, highlighting broader grid planning challenges.

The B.C. Utilities Commission is an independent watchdog that makes sure ratepayers — including BC Hydro customers — receive safe and reliable energy services, as utilities adapt to climate change risks, “at fair rates.”

The commission’s questions to BC Hydro include 14 about the “foundational enhancements” BC Hydro now says are necessary to shore up the Site C dam, powerhouse and spillways. 

The commission is asking BC Hydro to provide a timeline and overview of all geotechnical engineering studies and monitoring activities for the powerhouse, spillway and dam core areas, and to explain what specific risk management and mitigation practices were put into effect once risks were identified.

The commission also wants to know why construction activities continued on the right bank of the Peace River, where the powerhouse would be located, “after geotechnical risks materialized.” 

It’s asking if geotechnical risks played a role in BC Hydro’s decision in March “to suspend or not resume work” on any components of the generating station and spillways.

The commission also wants BC Hydro to provide an itemized breakdown of a $690 million increase in the main civil works contract — held by Spain’s Acciona S.A. and the South Korean multinational conglomerate Samsung C&T Corp. — and to explain the rationale for awarding a no-bid contract to an unnamed First Nation and if other parties were made aware of that contract. 

Peace River Jewels of the Peace Site C The Narwhal
Islands in the Peace River, known as the ‘jewels of the Peace’ will be destroyed for fill for the Site C dam or will be submerged underwater by the dam’s reservoir, a loss that opponents are sharing with northerners in community discussions. Photo: Byron Dueck

B.C. Utilities Commission chair and CEO David Morton said it’s not the first time the commission has requested additional information after receiving BC Hydro’s quarterly progress reports on the Site C dam. 

“Our staff reads them to make sure they understand them and if there’s anything in then that’s not clear we go then we do go through this, we call it the IR — information request — process,” Morton said in an interview.

“There are things reported in here that we felt required a little more clarity, and we needed a little more understanding of them, so that’s why we asked the questions.”

The questions were sent to BC Hydro on Oct. 23, the day before the provincial election, but Morton said the commission is extraordinarily busy this year and that’s just a coincidence. 

“Our resources are fairly strained. It would have been nice if it could have been done faster, it would be nice if everything could be done faster.” 

“These questions are not politically motivated,” Morton said. “They’re not political questions. There’s no reason not to issue them when they’re ready.”

The commission has asked BC Hydro to respond by Nov. 19.

Read more: Top B.C. government officials knew Site C dam was in serious trouble over a year ago: FOI docs

Morton said the independent commission’s jurisdiction is limited because the B.C. government removed it from oversight of the project. 

The commission, which would normally determine if a large dam like the Site C project is in the public’s financial interest, first examined BC Hydro’s proposal to build the dam in the early 1980s.

After almost two years of hearings, including testimony under oath, the commission concluded B.C. did not need the electricity. It found the Site C dam would have negative social and environmental impacts and said geothermal power should be investigated to meet future energy needs. 

The project was revived in 2010 by the BC Liberal government, which touted energy from the Site C dam as a potential source of electricity for California and a way to supply B.C.’s future LNG industry with cheap power.

Not willing to countenance another rejection from the utilities commission, the government changed the law, stripping the commission of oversight for the project. The NDP government, which came to power in 2017, chose not to restore that oversight.

“The approval of the project was exempt from our oversight,” Morton said. “We can’t come along and say ‘there’s something we don’t like about what you’re doing, we’re going to stop construction.’ We’re not in that position and that’s not the focus of these questions.” 

But the commission still retains oversight for the cost of construction once the project is complete, Morton said. 

“The cost of construction has to be recovered in [hydro] rates. That means BC Hydro will need our approval to recover their construction cost in rates, and those are not insignificant amounts, more than $10.7 billion, in all likelihood.” 

In order to recover the cost from ratepayers, the commission needs to be satisfied BC Hydro didn’t spend more money than necessary on the project, Morton said. 

“As you can imagine, that’s not a straight forward review to do after the fact, after a 10-year construction project or whatever it ends up being … so we’re using these quarterly reports as an opportunity to try to stay on top of it and to flag any areas where we think there may be areas we need to look into in the future.”

The price tag for the Site C dam was $10.7 billion before BC Hydro’s announcement at the end of July — a leap from $6.6 billion when the project was first announced in 2010 and $8.8 billion when construction began in 2015. 

Eliesen said the utilities commission should have been asking tough questions about the Site C dam far earlier. 

“They’ve been remiss in their due diligence activities … They should have been quicker in raising questions with BC Hydro, rather than allowing BC Hydro to be exceptionally late in submitting their reports.” 

BC Hydro is late in filing another Site C quarterly report, covering the period from April 1 to June 30. 

The quarterly reports provide the B.C. public with rare glimpses of a project that international hydro expert Harvey Elwin described as being more secretive than any hydro project he has encountered in five decades working on large dams around the world, including in China.

Read more: Site C dam secrecy ‘extraordinary’, international hydro construction expert tells court proceeding

Morton said the commission could have ordered regular reporting for the Site C project if it had its previous oversight capability.

“Then we would have had the ability to follow up and ultimately order any delinquent reports to be filed. In this circumstance, they are being filed voluntarily. They can file it as late as they choose. We don’t have any jurisdiction.” 

In addition to the six dozen questions, the commission has also filed confidential questions with BC Hydro. Morton said confidential information could include things such as competitive bid information. “BC Hydro itself may be under a confidentiality agreement not to disclose it.” 

With oversight, the commission would also have been able to drill down into specific project elements,  Morton said. 

“We would have wanted to ensure that the construction followed what was approved. BC Hydro wouldn’t have the ability to make significant changes to the design and nature of the project as they went along.”

BC Hydro has been criticized for changing the design of the Site C dam to an L-shape, which Eliesen said “has never been done anywhere in the world for an earthen dam.” 

Morton said an empowered commission could have opted to hold a public hearing about the design change and engage its own technical consultants, as it did in 2017 when the new NDP government asked it to conduct a fast-tracked review of the project’s economics. 

Construction Site C Dam
A recent report by a U.S. energy economist found cancelling the Site C dam project would save BC Hydro customers an initial $116 million a year, with increasing savings growing over time. Photo: Garth Lenz / The Narwhal

The commission’s final report found the dam could cost more than $12 billion, that BC Hydro had a historical pattern of overestimating energy demand and that the same amount of energy could be produced by a suite of renewables, including wind and proposed pumped storage such as the Meaford project, for $8.8 billion or less. 

The NDP government, under pressure from construction trade unions, opted to continue the project, refusing to disclose key financial information related to its decision. 

When the geotechnical problems were revealed in July, the government announced the appointment of former deputy finance minister Peter Milburn as a special Site C project advisor who will work with BC Hydro and the Site C project assurance board to examine the project and provide the government with independent advice.

Eliesen said BC Hydro and the B.C. government should never have allowed the recent diversion of the Peace River to take place given the tremendous geotechnical challenges the project faces and its unknown cost and schedule for completion. 

“It’s a disgrace and scandalous,” he said. “You can halt the river diversion, but you’ve got another four or five years left in construction of the dam. What are you going to do about all the cement you’ve poured if you’ve got stability problems?”

He said it’s counter-productive to continue with advice “from the same people who have been wrong, wrong, wrong,” without calling in independent global experts to examine the geotechnical problems. 

“If you stop construction, whether it takes three or six months, that’s the time that’s required in order to give yourself a comfort level. But continuing to do what you’ve been doing is not the right course. You should have to sit back.”

Eliesen said it reminded him of the Pete Seeger song Waist Deep in the Big Muddy, which tells the story of a captain ordering his troops to keep slogging through a river because they will soon be on dry ground. After the captain drowns, the troops turn around.

“It’s a reflection of the fact that if you don’t look at what’s new, you just keep on doing what you’ve been doing in the past and that, unfortunately, is what’s happening here in this province with this project.”

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Raindrop Triboelectric Energy Harvesting converts falling water into electricity using Teflon (PTFE) on indium tin oxide and an aluminum electrode, forming a transient water bridge; a low frequency nanogenerator for renewable, static electricity harvesting.

Key Points

A method using PTFE, ITO, and an aluminum electrode to turn raindrop impacts into low frequency electrical power.

✅ PTFE on ITO boosts charge transfer efficiency.

✅ Water bridge links electrodes for rapid discharge.

✅ Low frequency output suits continuous energy harvesting.

Scientists at the City University of Hong Kong have used a Teflon-coated surface and a phenomenon called triboelectricity to generate a charge from raindrops. “Here we develop a device to harvest energy from impinging water droplets by using an architecture that comprises a polytetrafluoroethylene [Teflon] film on an indium tin oxide substrate plus an aluminium electrode,” they explain in their new paper in Nature as a step toward cheap, abundant electricity in the long term.

Triboelectricity itself is an old concept. The word means “friction electricity”—from the Greek tribo, to rub or wear down, which is why a diatribe tires you out—and dates back a long, long time. Static electricity is the most famous kind of triboelectric, and related work has shown electricity from the night sky can be harvested as well in niche setups. In most naturally occurring kinds, scientists have studied triboelectric in order to avoid its effects, like explosions inside of grain silos or hospital workers touching off pure oxygen. (Blowing sand causes an electric field, and NASA even worries about static when astronauts eventually land on Mars.)

One of the most studied forms of intentional and useful triboelectric is in systems such as ocean wave generators where the natural friction of waves meets nanogenerators of triboelectric energy. These even already use Teflon, which has natural conductivity that makes it ideal for this job. But triboelectricity is chaotic, and harnessing it generally involves a bunch of complicated, intersecting variables that can vary with the hourly weather. Promises of static electricity charging devices have often been, well, so much hot, sandy wind.

The scientists at City University of Hong Kong used triboelectric ideas to turn falling raindrops into energy. They say previous versions of the same idea were not very efficient, with materials that didn’t allow for high-fidelity transfer of electrical charge. (Many sources of renewable energy aren’t yet as efficient to turn into power, both because of developing technology and because their renewability means even less efficient use could be better than, for example, fossil fuels, and advances in renewable energy storage could help.)

“[A]chieving a high density of electrical power generation is challenging,” the team explains in its paper. “Traditional hydraulic power generation mainly uses electromagnetic generators that are heavy, bulky, and become inefficient with low water supply.” Diversifying how power is generated by water sources such as oceans and rivers is good for the existing infrastructure as well as new installations.

The research team found that as simulated raindrops fell on their device, the way the water accumulated and spread created a link between their two electrodes, one Teflon-coated and the other aluminum. This watery de facto wire link closes the loop and allows accumulated energy to move through the system. Because it’s a mechanical setup, it’s not limited to salty seawater, and because the medium is already water, its potential isn’t affected by ambient humidity either.

Raindrop energy is very low frequency, which means this tech joins many other existing pushes to harvest continuously available, low frequency natural energy, including underwater 'kites' that exploit steady currents. To make an interface that increases “instantaneous power density by several orders of magnitude over equivalent devices,” as the researchers say they’ve done here, could represent a major step toward feasibility in triboelectric generation.

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