After 125 hours of rush repairs on damage caused by the major earthquake in Sichuan Province, the Zipingpu hydropower station resumed its power supply to the provincial grid. The station is located about 30 kilometers from the quake's epicenter.
All four units at the station suffered major damage, including generating equipment and outgoing lines. A team of experts led by Qiao Yong, Vice Minister of Water Resources, supervised repairs. Maintenance was carried out with support from Zipingpu Hydropower Development Company Limited, which owns the Zipingpu Water Control Project. As of May 17, three of the units were reconnected to the grid.
The Zipingpu Water Control Project is one of 10 key projects in the nation's West Development Program. The project comprises a 760-megawatt (MW) power station and a 156-meter-high concrete face rockfill dam with a total reservoir capacity of 1.126 billion cubic meters. The team of experts found that the dam was partially damaged by the quake but remains stable and safe overall.
For safety reasons, local authorities have decided to reduce the reservoir's water level as soon as possible. Resuming operation at the power station could improve the project's discharge capacity and ensure the dam's safety, as well as the power supply during ongoing rescue efforts.
According to the latest report from the State Electricity Regulatory Commission, 27 power plants were disconnected from the grid after the earthquake. As of May 18, seven power stations have resumed operation, and four have resumed power supply for plant service.
Most of the power plants that remain disconnected from the grid belong to the hydropower group in Maoxian County in northern Sichuan.
Nighttime Thermoelectric Generator converts radiative cooling into renewable energy, leveraging outer space cold; a Stanford-UCLA prototype complements solar, serving off-grid loads with low-power output during peak evening demand, using simple materials on a rooftop.
Key Points
A device converting nighttime radiative cooling into electricity, complementing solar for low-power evening needs.
✅ Uses thermocouples to convert temperature gradients to voltage.
✅ Exploits radiative cooling to outer space for night power.
✅ Complements solar; low-cost parts suit off-grid applications.
Two years ago, one freezing December night on a California rooftop, a tiny light shone weakly with a little help from the freezing night air. It wasn't a very bright glow. But it was enough to demonstrate the possibility of generating renewable power after the Sun goes down.
Working with Stanford University engineers Wei Li and Shanhui Fan, University of California Los Angeles materials scientist Aaswath Raman put together a device that produces a voltage by channelling the day's residual warmth into cooling air, effectively generating electricity from thin air with passive heat exchange.
"Our work highlights the many remaining opportunities for energy by taking advantage of the cold of outer space as a renewable energy resource," says Raman.
"We think this forms the basis of a complementary technology to solar. While the power output will always be substantially lower, it can operate at hours when solar cells cannot."
For all the merits of solar energy, it's just not a 24-7 source of power, although research into nighttime solar cells suggests new possibilities for after-dark generation. Sure, we can store it in a giant battery or use it to pump water up into a reservoir for later, but until we have more economical solutions, nighttime is going to be a quiet time for renewable solar power.
Most of us return home from work as the Sun is setting, and that's when energy demands spike to meet our needs for heating, cooking, entertaining, and lighting.
Unfortunately, we often turn to fossil fuels to make up the shortfall. For those living off the grid, it could require limiting options and going without a few luxuries.
Shanhui Fan understands the need for a night time renewable power source well. He's worked on a number of similar devices, including carbon nanotube generators that scavenge ambient energy, and a recent piece of technology that flipped photovoltaics on its head by squeezing electricity from the glow of heat radiating out of the planet's Sun-warmed surface.
While that clever item relied on the optical qualities of a warm object, this alternative device makes use of the good old thermoelectric effect, similar to thin-film waste-heat harvesting approaches now explored.
Using a material called a thermocouple, engineers can convert a change in temperature into a difference in voltage, effectively turning thermal energy into electricity with a measurable voltage. This demands something relatively toasty on one side and a place for that heat energy to escape to on the other.
The theory is the easy part – the real challenge is in arranging the right thermoelectric materials in such a way that they'll generate a voltage from our cooling surrounds that makes it worthwhile.
To keep costs down, the team used simple, off-the-shelf items that pretty much any of us could easily get our hands on.
They put together a cheap thermoelectric generator and linked it with a black aluminium disk to shed heat in the night air as it faced the sky. The generator was placed inside a polystyrene enclosure sealed with a window transparent to infrared light, and linked to a single tiny LED.
For six hours one evening, the box was left to cool on a roof-top in Stanford as the temperature fell just below freezing. As the heat flowed from the ground into the sky, the small generator produced just enough current to make the light flicker to life.
At its best, the device generated around 0.8 milliwatts of power, corresponding to 25 milliwatts of power per square metre.
That might just be enough to keep a hearing aid working. String several together and you might just be able to keep your cat amused with a simple laser pointer. So we're not talking massive amounts of power.
But as far as prototypes go, it's a fantastic starting point. The team suggests that with the right tweaks and the right conditions, 500 milliwatts per square metre isn't out of the question.
"Beyond lighting, we believe this could be a broadly enabling approach to power generation suitable for remote locations, and anywhere where power generation at night is needed," says Raman.
While we search for big, bright ideas to drive the revolution for renewables, it's important to make sure we don't let the smaller, simpler solutions like these slip away quietly into the night.
PGE Residential Energy Storage Pilot aggregates 525 home batteries into a virtual power plant, enabling distributed energy resources, smart grid control, renewable energy optimization, demand response, and backup power across Portland General Electric's area.
Key Points
A PGE program aggregating 525 batteries into a utility-run virtual power plant for renewables support and backup power.
✅ Up to 4 MW aggregated capacity from 525 residential batteries
✅ Monthly credits: $40 ($20 with solar) for grid services
✅ Enhances smart grid, DERs, resilience, and outage backup
Portland General Electric Company is set to launch a pilot program that will incentivize installation and connection of 525 residential energy storage batteries that PGE will dispatch, contributing up to four megawatts of energy to PGE's grid. The distributed assets will create a virtual power plant made up of small units that can be operated individually or combined to serve the grid, adding flexibility that supports PGE's transition to a clean energy future. When the program launches this fall, incentives will be available to residential customers across PGE's service area. Rebates will be available to customers within three neighborhoods participating in PGE's Smart Grid Test Bed, and income-qualified customers participating in Energy Trust of Oregon's Solar Within Reach offer.
PGE will study the full benefits of energy storage that these distributed energy assets can provide the grid while also increasing resiliency for each participating customer. PGE will operate and test the benefits of using homes' batteries, each capable of storing 12 to 16 kWh of energy, to optimize the use of renewable energy and grid capabilities. In the event of a power outage, participating customers can rely on them as a backup power resource.
"Our vision for clean energy relies on a smart, integrated grid. One of the ways that we'll achieve that is through creative partnerships and diversified energy resources, including those behind-the-meter," said Larry Bekkedahl, vice president of Grid Architecture, Integration and Systems Operation. "This pilot project will allow PGE to integrate even more intermittent renewable energy and enhance grid capabilities while also giving participating customers peace of mind in the event of an outage."
Energy storage maximizes renewables and the grid, improves power quality
Energy storage, including long-duration energy storage solutions, is vital to help capture and store energy from renewable power sources, such as wind and solar, that are more variable. As a virtual power plant, the residential battery storage pilot will create a single resource that can help the grid balance energy production with energy demand, freeing up the generation resources that are typically held on standby, ready to kick in when the wind doesn't blow or the sun doesn't shine. As a clean energy option that takes the place of standby resources, the virtual power plant also gives customers access to reliable energy, even in the event of system outages.
The test program will also allow PGE to test new smart-grid control devices across its distribution system that will more effectively allow a two-way exchange between PGE and pilot participants. The new controls will more actively manage the way that electricity is distributed across PGE's system to incorporate energy that customers generate, such as through solar panels, while also meeting power demand that is less predictable, such as for charging electric vehicles, supporting EVs for grid stability strategies. The controls will allow PGE to more actively manage power distribution to improve power quality for all customers.
Select rebates and incentives will be available to participants, aligned with electric vehicle programs that encourage transportation electrification
When it launches in fall 2020, participation in the program will be available to residential customers, including:
* Those across PGE's service area who already have or are installing a qualifying battery. Participation will require an application, and in exchange for allowing PGE to operate their battery for grid services, similar to programs where EV owners selling power back for compensation, participating customers will receive a monthly bill credit of $40, or $20 if the battery is charged with solar power.
* Customers across PGE's service area who are participating in the Solar Within Reach offering from Energy Trust of Oregon. Participants will be eligible for a $5,000 instant rebate in addition to the monthly bill credits.
* Those living within the PGE Smart Grid Test Bed who purchase a battery will be eligible for an instant rebate, in addition to the monthly bill credit of $40 or $20, which will allow PGE to test the localized grid impact of having a large concentration of battery storage devices available on one substation and explore interfaces with vehicle-to-grid pilots in the region.
PGE is working with Energy Trust to cost-effectively procure the residential battery storage systems, as utilities invest in advanced storage solutions across the region, by leveraging the existing Solar incentive program infrastructure and trade ally contractor network. Customers who participate in the program will own their battery systems, and rebates will only be available for systems installed by an Energy Trust solar trade ally. The program may also accept customers with a qualifying battery that is was previously installed, following a process to ensure safe operation.
More information about Portland General Electric's energy storage program is available at PortlandGeneral.com/energystorage and will be updated with details about the residential battery storage pilot program.
UK Peak Power Prices surged as low wind speeds forced National Grid to rely on gas-fired plants and coal generation, amid soaring wholesale gas prices and weak wind generation during the energy crisis.
Key Points
UK Peak Power Prices are electricity costs at peak hours, driven by wind output, gas reliance, and market dynamics.
✅ Spikes when wind generation drops and demand rises.
✅ Driven by gas-fired plants, coal backup, and wholesale gas prices.
✅ Moderate as wind output recovers and interconnectors supply.
Low wind speeds pushed peak hour power prices to the second highest level for at least three years on Monday, a move consistent with UK electricity prices hitting a 10-year high earlier this year, as Britain’s grid was forced to increase its reliance on gas-fired power plants and draw on coal generation.
Calm weather this year has exacerbated the energy price crisis in the UK, as gas-fired power stations have had to pick up the slack from wind farms. Energy demand has surged as countries open up from pandemic restrictions, which together with lower supplies from Russia to western Europe, has sent wholesale gas prices soaring.
Power prices in the UK for the peak evening period between 5pm and 6pm on Monday surpassed £2,000 per megawatt hour, only the second time they have exceeded that level in recent years.
This was still below the levels reached at the height of the gas price crisis in mid-September, when they hit £2,500/MWh, according to the energy consultancy Cornwall Insight, whose records date back to 2018.
Low wind speeds were the main driver behind Monday’s price spike, although expectations of a pick-up in wind generation on Tuesday, after recent record wind generation days, should push them back down to similar levels seen in recent weeks, analysts said.
Despite the expansion of renewables, such as wind and solar, over the past decade, with instances of wind leading the power mix in recent months, gas remains the single biggest source of electricity generation in Britain, typically accounting for nearly 40 per cent of output.
At lunchtime on Monday, gas-fired power plants were producing nearly 55 per cent of electricity, while coal accounted for 3 per cent, reflecting more power from wind than coal in 2016 milestones. Britain’s wind farms were contributing 1.67 gigawatts or just over 4 per cent, according to data from the Drax Electrics Insights website. Over the past 12 months, wind farms have produced 21 per cent of the UK’s electricity on average.
National Grid, which manages the UK’s electricity grid, has been forced on a number of occasions in recent months to ask coal plants to fire up to help offset the loss of wind generation, after issuing a National Grid short supply warning to the market. The government announced in June that it planned to bring forward the closure of the remaining coal stations to the end of September 2024.
Ministers also committed this year to making Britain’s electricity grid “net zero carbon” by 2035, and milestones such as when wind was the main source underline the transition, although some analysts have pointed out that would not signal the end of gas generation.
Since the start of the energy crisis in August, 20 energy suppliers have gone bust as they have struggled to secure the electricity and gas needed to supply customers at record wholesale prices, with further failures expected in coming weeks.
Phil Hewitt, director of the consultancy EnAppSys, said Monday’s high prices would further exacerbate pressures on those energy suppliers that do not have adequate hedging strategies. “This winter is a good time to be a generator,” he added.
Energy companies including Orsted of Denmark and SSE of the UK have reported some of the lowest wind speeds for at least two decades this year, even though record output during Storm Malik highlighted the system's volatility.
According to weather modelling group Vortex, the strength of the wind blowing across northern Europe has fallen by as much as 15 per cent on average in places this year, which some scientists suggest could be due to climate change.
Hydro-Qu e9bec COVID-19 M&A Pause signals a halt to international expansion as falling electricity demand, weaker exports, and revenue pressure shift capital to the Quebec economy, prioritizing domestic investment, strategic plan revisions, and risk management.
Key Points
Hydro-Qu e9bec COVID-19 M&A Pause halts overseas deals, shifting investment to Quebec as demand, exports and revenue fall.
✅ International M&A on hold; capital reallocated to Quebec projects
✅ Lower electricity demand reduces exports and spot prices
✅ Strategic plan and 2020 guidance revised downward
Quebec’s state-owned power generator and distributor has put international mergers and acquisitions on hold for the foreseeable future because of the COVID-19 crisis, chief financial officer Jean-Hugues Lafleur said Friday.
Former chief executive officer Éric Martel, who left last month, had made foreign expansion a key tenet of his growth strategy.
“We’re in revision mode” as pertains to acquisitions, Lafleur told reporters on a conference call, as the company pursues a long-term strategy to wean the province off fossil fuels at home as well. “I don’t see how Hydro-Québec could take $5 billion now and invest it in Chile because we have an investment opportunity there. Instead, the $5 billion will be invested here to support the Quebec economy. We’re going to make sure the Quebec economy recovers the right way before we go abroad.”
Lafleur spoke after Hydro-Québec reported a 14-per-cent drop in first-quarter profit and warned full-year results will fall short of expectations as COVID-19 weighs on power demand.
Net income in the three-month period ended March 31 was $1.53 billion, down from $1.77 billion a year ago, Hydro-Québec said in a statement. Revenue fell about six per cent to $4.37 billion.
“Due to the economic downturn resulting from the current crisis, we’re anticipating lower electricity sales in all of our markets,” Lafleur said. “Consequently, the financial outlook for 2020 set out in the strategic plan 2020–2024, which also reflects the province’s no-nuclear stance, will be revised downward.”
It’s still too early to determine the scope of the revision, the company said in its quarterly report. Hydro-Québec was targeting net income of between $2.8 billion and $3 billion in 2020, according to its strategic plan.
The first quarter was the utility’s last under Martel, who quit to take over at jetmaker Bombardier Inc. Quebec appointed former Énergir CEO Sophie Brochu to replace him, effective April 6.
First-quarter results “weren’t significantly affected” by the pandemic, Lafleur said on a conference call with reporters. Electricity sales generated $294 million less than a year ago due primarily to milder temperatures, he said.
Results will start to reflect COVID-19’s impact in the second quarter, though NB Power has signed three deals to bring more Quebec electricity into the province that could cushion some exports.
Electricity consumption in Quebec has fallen five per cent in the past two months, paced by an 11-per-cent plunge for commercial and institutional clients, and cities such as Ottawa saw a demand plunge during closures.
Industrial customers such as pulp and paper producers have also curbed power use, and it’s hard to see demand rebounding this year, Lafleur said.
“What we’ve lost since the start of the pandemic is not coming back,” he said.
Demand on export markets, meanwhile, has shrunk between six per cent and nine per cent since mid-March. The drop has been particularly steep in Ontario, reaching as much as 12 per cent, after the province chose not to renew its electricity deal with Quebec earlier this year, compared with declines of up to five per cent in New England and eight per cent in New York.
Spot prices in the U.S. have retreated in tandem, falling this week to as low as 1.5 U.S. cents per kilowatt-hour, Lafleur said. Hydro-Québec’s hedging strategy — which involves entering into fixed-price sales contracts about a year ahead of time — allowed the company to export power for an average of 4.9 U.S. cents per kilowatt-hour in the first quarter, compared with the 2.2 cents it would have otherwise made.
Investments will decline this year as construction activity proceeds at reduced speed, Lafleur said. Hydro-Québec was initially planning to invest about $4 billion in the province, he said, as it works to increase hydropower capacity to more than 37,000 MW across its fleet.
Physical distancing measures “are having an impact on productivity,” Lafleur said. “We can’t work the way we wanted, and project costs are going to be affected. Anytime we send workers north on a plane, we need to leave an empty seat beside them.”
EU Power Market Overhaul targets soaring electricity prices by decoupling gas from power, boosting renewables, refining price caps, and stabilizing grids amid inflation, supply shocks, droughts, nuclear outages, and intermittent wind and solar.
Key Points
EU plan to redesign electricity pricing, curb gas-driven costs, boost renewables, and protect consumers from volatility.
✅ Decouples power prices from marginal gas generation
✅ Caps non-gas revenues to fund consumer relief
✅ Supports grid stability with storage, demand response, LNG
While energy prices are soaring around the world, Europe is in a particularly tight spot. Its heavy dependence on Russian gas -- on top of droughts, heat waves, an unreliable fleet of French nuclear reactors and a continent-wide shift to greener but more intermittent sources like solar and wind -- has been driving electricity bills up and feeding the highest inflation in decades. As Europe stands on the brink of a recession, and with the winter heating season approaching, officials are considering a major overhaul of the region’s power market to reflect the ongoing shift from fossil fuels to renewables.
1. How is electricity priced? Unlike oil or natural gas, there’s no efficient way to save lots of electricity to use in the future, though projects to store electricity in gas pipes are emerging. Commercial use of large-scale batteries is still years away. So power prices have been set by the availability at any given moment. When it’s really windy or sunny, for example, then more is produced relatively cheaply and prices are lower. If that supply shrinks, then prices rise because more generators are brought online to help meet demand -- fueled by more expensive sources. The way the market has long worked is that it is that final technology, or type of plant, needed to meet the last unit of consumption that sets the price for everyone. In Europe this year, that has usually meant natural gas.
2. What is the relationship between power and gas? Very close. Across western Europe, gas plants have been a vital part of the energy infrastructure for decades, with Irish price spikes highlighting dispatchable power risks, fed in large part by supplies piped in from Siberia. Gas-fired plants were relatively quick to build and the technology straightforward, at least compared with nuclear plants and burns cleaner than coal. About 18% of Europe’s electricity was generated at gas plants last year; in 2020 about 43% of the imported gas came from Russia. Even during the depths of the Cold War, there’d never been a serious supply problem -- until the relationship with Russia deteriorated this year after it invaded Ukraine. Diversifying away from Russia, such as by increasing imports of liquefied natural gas, requires new infrastructure that takes a lot of time and money.
3. Why does it work this way? In theory, the relationship isn’t different from that with coal, for example. But production hiccups and heatwave curbs on plants from nuclear in France to hydro in Spain and Norway significantly changed the generation picture this year, and power hit records as plants buckled in the heat. Since coal-fired and nuclear plants are generally running all the time anyway, gas plants were being called upon more often -- at times just to keep the lights on as summer temperatures hit records. And with the war in Ukraine resulting in record gas prices, that pushed up overall production costs. It’s that relationship that has made the surging gas price the driver for electricity prices. And since the continent is all connected, it has pushed up prices across the region. The value of the European power market jumped threefold last year, to a record 836 billion euros ($827 billion today).
4. What’s being considered? With large parts of European industry on its knees and households facing jumps in energy bills of several hundred percent, as record electricity prices ripple through markets, the pressure on governments and the European Union to intervene has never been higher. One major proposal is to impose a price cap on electricity from non-gas producers, with the difference between that and the market price channeled to relief for consumers. While it sounds simple, any such changes would rip up a market design that’s worked for decades and could threaten future investments because of unintended consequences.
5. How did this market evolve? The Nordic region and the British market were front-runners in the 1990s, then Germany followed and is now the largest by far. A trader can buy and sell electricity delivered later on same day in blocks of an hour or even down to 15-minute periods, to meet sudden demand or take advantage of price differentials. The price for these contracts is decided entirely by the supply and demand, how much the wind is blowing or which coal plants are operating, for example. Demand tends to surge early in the morning and late afternoon. This system was designed when fossil fuels provided the bulk of power. Now there are more renewables, which are less predictable, with wind and solar surpassing gas in EU generation last year, and the proposed changes reflect that shift.
6. What else have governments done? There are also traders who focus on longer-dated contracts covering periods several years ahead, where broader factors such as expected economic output and the extent to which renewables are crowding out gas help drive prices. This year’s wild price swings have prompted countries including Germany, Sweden and Finland to earmark billions of euros in emergency liquidity loans to backstop utilities hit with sudden margin calls on their trading.
SM-1A Nuclear Plant Decommissioning details the US Army Corps of Engineers' removal of the Fort Greely reactor, Cold War facility dismantling, environmental monitoring, remote-site power history, and timeline to 2026 under a deactivated nuclear program.
Key Points
Army Corps plan to dismantle Fort Greely's SM-1A reactor and complete decommissioning of remaining systems by 2026.
✅ Built for remote Arctic radar support during the Cold War
✅ High costs beat diesel; program later deemed impractical
✅ Reactor parts removed; residuals monitored; removal by 2026
The US Army Corps of Engineers has begun decommissioning Alaska’s only nuclear power plant, SM-1A, which is located at Fort Greely, even as new US reactors continue to take shape nationwide. The $17m plant closed in 1972 after ten years of sporadic operation. It was out of commission from 1967 to 1969 for extensive repairs. Much of has already been dismantled and sent for disposal, and the rest, which is encased in concrete, is now to be removed.
The plant was built as part of an experimental programme to determine whether nuclear facilities, akin to next-generation nuclear concepts, could be built and operated at remote sites more cheaply than diesel-fuelled plants.
"The main approach was to reduce significant fuel-transportation costs by having a nuclear reactor that could operate for long terms, a concept echoed in the NuScale SMR safety evaluation process, with just one nuclear core," Brian Hearty said. Hearty manages the Army Corps of Engineers’ Deactivated Nuclear Power Plant Program.
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He said the Army built SM-1A in 1962 hoping to provide power reliably at remote Arctic radar sites, where in similarly isolated regions today new US coal plants may still be considered, intended to detect incoming missiles from the Soviet Union at the height of the Cold War. He added that the programme worked but not as well as Pentagon officials had hoped. While SM-1A could be built and operated in a cold and remote location, its upfront costs were much higher than anticipated, and it costs more to maintain than a diesel power plant. Moreover, the programme became irrelevant because of advances in Soviet rocket science and the development of intercontinental ballistic missiles.
Hearty said the reactor was partially dismantled soon after it was shut down. “All of the fuel in the reactor core was removed and shipped back to the Atomic Energy Commission (AEC) for them to either reprocess or dispose of,” he noted. “The highly activated control and absorber rods were also removed and shipped back to the AEC.”
The SM-1A plant produced 1.8MWe and 20MWt, including steam, which was used to heat the post. Because that part of the system was still needed, Army officials removed most of the nuclear-power system and linked the heat and steam components to a diesel-fired boiler. However, several parts of the nuclear system remained, including the reactor pressure vessel and reactor coolant pumps. “Those were either kept in place, or they were cut off and laid down in the tall vapour-containment building there,” Hearty said. “And then they were grouted and concreted in place.” The Corps of Engineers wants to remove all that remains of the plant, but it is as yet unclear whether that will be feasible.
Meanwhile, monitoring for radioactivity around the facility shows that it remains at acceptable levels. “It would be safe to say there’s no threat to human health in the environment,” said Brenda Barber, project manager for the decommissioning. Work is still in its early stages and is due to be completed in 2026 at the earliest. Barber said the Corps awarded the $4.6m contract in December to a Virginia-based firm to develop a long-range plan for the project, similar in scope to large reactor refurbishment efforts elsewhere. Among other things, this will help officials determine how much of the SM-1A will remain after it’s decommissioned. “There will still be buildings there,” she said. “There will still be components of some of the old structure there that may likely remain.”
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