Electricity News in August 2022
Germany considers U-turn on nuclear phaseout
Germany Nuclear Power Extension debated as Olaf Scholz weighs energy crisis, gas shortages from Russia, slow grid expansion in Bavaria, and renewables delays; stress test results may guide policy alongside coal plant reactivations.
Key Points
A proposal to delay Germany's nuclear phaseout to stabilize power supply amid gas cuts and slow grid upgrades.
✅ Driven by Russia gas cuts and Nord Stream 1 curtailment
✅ Targets Bavaria grid bottlenecks; renewables deployment delays
✅ Decision awaits grid stress test; coalition parties remain split
The German chancellor on Wednesday said it might make sense to extend the lifetime of Germany's three remaining nuclear power plants.
Germany famously decided to stop using atomic energy in 2011, and the last remaining plants were set to close at the end of this year.
However, an increasing number of politicians have been arguing for the postponement of the closures amid energy concerns arising from Russia's invasion of Ukraine. The issue divides members of Scholz's ruling traffic-light coalition.
What did the chancellor say?
Visiting a factory in western Germany, where a vital gas turbine is being stored, Chancellor Olaf Scholz was responding to a question about extending the lifetime of the power stations.
He said the nuclear power plants in question were only relevant for a small proportion of electricity production. "Nevertheless, that can make sense," he said.
The German government has previously said that renewable energy alternatives are the key to solving the country's energy problems.
However, Scholz said this was not happening quickly enough in some parts of Germany, such as Bavaria.
"The expansion of power line capacities, of the transmission grid in the south, has not progressed as quickly as was planned," the chancellor said.
"We will act for the whole of Germany, we will support all regions of Germany in the best possible way so that the energy supply for all citizens and all companies can be guaranteed as best as possible."
The phaseout has been planned for a long time. Germany's Social Democrat government, under Merkel's predecessor Gerhard Schröder, had announced that Germany would stop using nuclear power by 2022 as planned.
Schröder's successor Angela Merkel — herself a former physicist — had initially sought to extend to life of existing nuclear plants to as late as 2037. She viewed nuclear power as a bridging technology to sustain the country until new alternatives could be found.
However, Merkel decided to ditch atomic energy in 2011, after the Fukushima nuclear disaster in Japan, setting Germany on a path to become the first major economy to phase out coal and nuclear in tandem.
Nuclear power accounted for 13.3% of German electricity supply in 2021. This was generated by six power plants, of which three were switched off at the end of 2021. The remaining three — Emsland, Isar and Neckarwestheim — were due to shut down at the end of 2022.
Germany's energy mix 1st half of 2022
The need to fill an energy gap has emerged after Russia dramatically reduced gas deliveries to Germany through the Nord Stream 1 pipeline, though nuclear power would do little to solve the gas issue according to some officials. Officials in Berlin say the Kremlin is seeking to punish the country — which is heavily reliant on Moscow's gas — for its support of Ukraine and sanctions on Russia.
Germany has already said it will temporarily fire up mothballed coal and oil power plants in a bid to solve the looming power crisis.
Social Democrat Scholz and Germany's energy minister, Robert Habeck, from the Green Party, a junior partner in the three-way coalition government, had previously ruled out any postponement of the nuclear phasout, despite debate over a possible resurgence of nuclear energy among some lawmakers. The third member of Scholz's coalition, the neoliberal Free Democrats, has voiced support for the extension, as has the opposition conservative CDU-CSU bloc.
Berlin has said it will await the outcome of a new "stress test" of Germany's electric grid before deciding on the phaseout.
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Germany gets solar power boost amid energy crisis
Germany Solar Boom is accelerating amid energy security pressures, with photovoltaic capacity surging as renewables displace gas. Policy incentives, grid upgrades, and storage, plus agrivoltaics and rooftop systems, position solar as cornerstone of decarbonization.
Key Points
Germany Solar Boom is rapid PV growth enhancing energy security, cutting emissions, and expanding domestic, low-carbon electricity.
✅ Targets 250 GW PV by 2032 to meet rising electricity demand.
✅ Rooftop, agrivoltaics, and BIPV reduce land use and grid stress.
✅ Diversifies supply chains beyond China; boosts storage and flexibility.
Europe is in crisis mode. Climate change, increasing demand for energy, the war in Ukraine and Russia's subsequent throttling of oil and gas deliveries have pushed the continent into a new era.
Germany has been trapped in a corner. The country relies heavily on cheap imported natural gas to run its industries. Some power plants also use gas to produce electricity. Finding enough substitutes quickly is nearly impossible.
Ideas to prevent a looming power crisis in Germany have ranged from reducing demand to keeping nuclear power plants online past their official closing date at the end of the year. Large wind turbines are doing their part, but many people don't want them in their backyard.
Green activists have long believed renewable energies are the answer to keeping the lights on. But building up these capabilities takes time. Now many experts once again see solar power as a shining light at the end of the tunnel, as global renewables set fresh records worldwide. Some say a solar boom is in the making.
Before the war in Ukraine put energy security at the forefront, the new German government had already pledged that renewable sources — wind and solar — would make up 80% of electricity production by 2030 instead of 42% today. By 2035, electricity generation should be carbon neutral.
It is an ambitious plan, but the country seems to be on its way. July was the third month in a row when solar power output soared to a record level, trade publication pv magazine reported, and clean energy's share reached about 50% in Germany according to recent assessments. For the month, photovoltaic (PV) systems generated 8.23 terawatt hours of power, around a fifth of net electricity production. They were only behind lignite-fired power plants, which brought in nearly 22% of net production.
Solar cells hanging on a modular solar house during the Solar Decathlon Europe in Wuppertal, Germany
Solar panels can come in many different shapes and sizes, and be used in many different ways
Last year, Germany added more than 5 gigawatts of solar power capacity, 10% more than in 2020. That took the total solar power capacity to 59 gigawatts, overtaking installed onshore wind power capacity in Germany, pv magazine said in January. Last year's solar production was about 9% of gross electricity consumption, according to Harry Wirth, who is head of photovoltaic modules and power plant research at the Fraunhofer Institute for Solar Energy Systems in Freiburg.
"For 2032, the government target is around 250 gigawatts of solar energy. According to their estimates, electricity consumption will increase to 715 terawatt hours by 2030," Wirth told DW. A different study by consultancy McKinsey says this is the lower limit. "So if we assume 730 terawatt hours for 2032, we would be at around 30% photovoltaic electricity in gross electricity consumption," he added.
The energy expert also envisions great potential to install more solar panels without taking up valuable land. Besides adding them on top of parking garages or buildings, photovoltaic parts can be integrated into the exterior of buildings or even on the outside of e-vehicles. This would "not only produce electricity on surfaces already in use, but it would also create synergies in its own application," said Wirth.
Foreign investment in German solar
It is not just researchers that are taking note. Big businesses are stepping in too. In July, Portuguese clean energy firm EDP Renovaveis (EDPR) announced it had agreed to take a 70% interest in Germany's Kronos Solar Projects, a solar developer, for €250 million ($254 million).
The Munich-based company has a portfolio of 9.4 gigawatts of solar projects in different stages of development in Germany, France, the Netherlands and the UK, according to the press release announcing the purchase. Germany represents close to 50% of the acquired solar portfolio.
EDPR, which claims to be the fourth-largest renewable energy producer worldwide, said it generated 17.8 terawatt hours of clean energy in the first half of 2022.
Miguel Stilwell d'Andrade, chief executive of EDPR and its parent EDP, said they have great expectations from Germany in particular as "it is a key market in Europe with reinforced renewable growth targets."
Fabian Karthaus is one of the first farmers in Germany to grow raspberries and blueberries under photovoltaic panels. His solar field near the city of Paderborn in northwestern Germany is 0.4 hectares (about 1 acre), but he would like to expand it to 10. He could then generate enough electricity for around 4,000 households — and provide more berries for supermarkets.
Germany was once a leader in solar power. For many years the country enjoyed a large share of the world's total solar capacities. A lot of that early success had to do with innovative government support. That support, however, proved too successful for some as a fall in wholesale electricity prices in Northern Europe hurt the profits of power companies, leading to calls for a change in the rules.
Updated regulations, and changes to the Renewable Energy Sources Act that reduced feed-in tariffs slowed things down. Feed-in tariffs usually grant long-term grid access and above-market price guarantees in an effort to support fledgling industries.
With less direct financial incentives, the industry was neglected leaving it open for competitors. The pace of solar infrastructure growth has also been hampered by issues of red tape, supply chain backlogs, a lack of skilled technicians and, despite solar-plus-storage now undercutting conventional power in Germany, a shortage of storage for electricity produced when it is not needed.
Now the war in Ukraine and Europe's dependency on Russia is refocusing efforts and "will strengthen the determination for an ambitious PV expansion," said Wirth. But the biggest challenge to the region's solar industry remains China.
Public buildings can play a big role, not just because of their size, but because the government is in charge of them
An overreliance on China
China took an early interest in photovoltaic technology and soon galloped past countries like the US, Japan and Germany thanks to huge state subsidies that manufacturers enjoyed. Today, it has become the place to go for all things solar, even as Europe turns to US solar equipment suppliers to diversify procurement.
A new report from the International Energy Agency puts it into numbers. "China has invested over $50 billion in new PV supply capacity — 10 times more than Europe — and created more than 300,000 manufacturing jobs across the solar PV value chain since 2011."
Today China has over 80% of all solar panel manufacturing capacity and is home to the top-10 suppliers of photovoltaic manufacturing equipment. Such a high concentration has led to some incredible realities, like the fact that "one out of every seven panels produced worldwide is manufactured by a single facility," according to the report.
These economies of scale have brought down costs, and the country can make solar components 35% cheaper than in Europe. This gives China outsized power and makes the industry susceptible to supply chain bottlenecks. To diversify the industry and get back some of this market, Europe needs to invest in innovation and make solar growth a top priority.
Germany has several high-tech photovoltaic manufacturers and research institutes. But it only has one manufacturer of solar cells specializing in high-performance heterojunction technology, says Wirth. Yet even though the European photovoltaic industry is fragmented and not what it once was, he is still counting on big demand for solar technology in the foreseeable future, with markets like Poland accelerating adoption across the region.
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Norway Considers Curbing Electricity Exports to Avoid Shortages
Norway Electricity Export Limits weigh hydro reservoirs, energy security, EU-UK interconnectors, and record power prices amid Russia gas cuts; Statnett grid constraints and subsidies debate intensify as reservoir levels fall, threatening winter supply.
Key Points
Rules to curb Norway's power exports when reservoirs are very low, protecting supply security and easing extreme prices.
✅ Triggered by low hydro levels and record day-ahead prices
✅ Considers EU/UK cables, Statnett operations, seasonal thresholds
✅ Aims to secure winter supply and expand subsidies
Norway, one of Europe’s biggest electricity exporters, is considering measures to limit power shipments to prevent domestic shortages amid surging prices, according to local media reports.
The government may propose a rule to limit exports if the water level for Norway’s hydro reservoirs drops to “very low” levels, to ensure security of supply, said Energy Minister Terje Aasland, according NTB newswire. The limit would take account of seasonality and would differ across the about 1,800 hydro reservoirs, he said.
Russia’s gas supply cuts in retaliation for European sanctions over the war in Ukraine have triggered the continent’s worst energy crisis in decades, with demand surging for cheap Norwegian hydro electricity. Yet the government faces increasing calls from the public and opposition to limit flows abroad. Prices are near record levels in some parts of the Nordic nation as hydro-reservoir levels have plunged in the south after a drier-than-normal spring.
The government has been under pressure to do something about exports since before April. Flows on the cables are regulated by deals with both the European Union and the UK energy market and Norway can’t simply cut flows. It’s the latest test of European solidarity and a wake-up call for Europe when it comes to energy supplies. Hungary is trying to ban energy exports after it declared an energy emergency.
Back in May, grid operator Statnett SF warned that Norway could face a strained power situation after less snowfall than usual during the winter. At the end of last week, the level of filling in Norwegian hydro reservoirs was 66.5%, compared with a median 74.9% for the corresponding time in 2002-2021, regulator NVE said. Day-ahead electricity prices in southwest Norway soared to a record 423 euros per megawatt-hour late last month, partly due to bottlenecks in the grid limiting supply from the northern regions.
The grid operator has been asked to present by Oct. 1 possible measures that need to be taken to secure supply and infrastructure security ahead of the winter. Statnett operates cables to the UK and Germany aimed at selling surplus electricity and would likely take a financial hit if curbs were introduced. “Operations of these will always follow current laws and regulations,” Irene Meldal, a company spokeswoman, said Friday by email.
Premier Jonas Gahr Store signaled his minority government will file proposals that also include more subsidies to families and companies and align with Europe’s emergency price measures during August, according to an interview with TV2 on Thursday. Meanwhile, opposition politicians plan to hold an extraordinary parliament meeting to discuss boosting the subsidies.
Aasland will summon the parties’ representatives to a meeting on Monday on the electricity crisis, the Aftenposten newspaper reported on Friday, without citing anyone. He intends to inform the parties about the ongoing work and aims to “avoid rushed decisions” by the parliamentary majority.
Norway Faces Pressure to Curb Power Exports as Prices Surge (1)
The nation gets almost all of its electricity from its vast hydro resources. Historically, it has been able to export a hefty surplus and still have among the lowest prices in Europe.
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European Power Hits Records as Plants Start to Buckle in Heat
European Power Crisis intensifies as record electricity prices, nuclear output cuts, gas supply strain, heatwave drought, and Rhine shipping bottlenecks hit Germany, France, and Switzerland, tightening winter storage and driving long-term contracts higher.
Key Points
A surge in European power prices from heatwaves, nuclear curbs, Rhine coal limits, and reduced Russian gas supply.
✅ Record year-ahead prices in Germany and France
✅ Nuclear output curbed by warm river cooling limits
✅ Rhine low water disrupts coal logistics and generation
Benchmark power prices in Europe hit fresh records Friday as utilities are increasingly reducing electricity output in western Europe because of the hot weather.
Next-year contracts in Germany and France, Europe’s biggest economies rose to new highs after Switzerland’s Axpo Holding AG announced curbs at one of its nuclear plants. Electricite de France SA is also reducing nuclear output because of high river temperatures and cooling water restrictions, while Uniper SE in Germany is struggling to get enough coal up the river Rhine.
Europe is suffering its worst energy crunch in decades, and losing nuclear power is compounding the strain as gas cuts made by Russia in retaliation for sanctions drive a surge in prices. The extreme heat led to the driest July on record in France and is underscoring the impact that a warming climate is having on vital infrastructure.
Water levels on Germany’s Rhine have fallen so low that the river may effectively close soon, impacting supplies of coal to the plants next to it. The Rhone and Garonne in France and the Aare in Switzerland are all too warm to be used to cool nuclear plants effectively, forcing operators to limit energy output under environmental constraints.
Northwest European weather forecast for the next two weeks:
relates to European Power Hits Records as Plants Start to Buckle in Heat
The German year-ahead contract gained as much as 2% to 413 euros a megawatt-hour on the European Energy Exchange AG. The French equivalent rose 1.9% to a record 535 euros. Long-term prices are coming under pressure because producing less power from nuclear and coal will increase the demand for natural gas, which is badly needed to fill storage sites ahead of the winter.
France to Curb Nuclear Output as Europe’s Energy Crisis Worsens
Uniper SE said on Thursday that two of its coal-fired stations along the Rhine may need to curb output during the next few weeks as transporting coal along the Rhine becomes impossible.
Plants on the river near Mannheim and Karlsruhe, operated by Grosskraftwerk Mannheim AG and EnBW AG, have previously struggled to source coal because of the shallow water, even as German renewables deliver more electricity than coal and nuclear at times. Both companies said generation hasn’t been affected yet.
“The low tide is not currently affecting our generation of energy because our plants do not have the need for continuous fresh water,” a Steag GmbH spokesman said on Friday. “But the low tide level can make running plants and transporting coal more complicated than usual.”
The spokesman said though that there is slight reduction in output of about 10 to 15 megawatts, which would equate to a few percent, because of the hot temperatures. “This has been happening over some time now and is a problem for everyone because the plant system is not designed to withstand such hot temperatures,” he said.
Related News
California scorns fossil fuel but can't keep the lights on without it
California fossil fuel grid reliability plan addresses heat wave demand, rolling blackouts, and grid stability by temporarily procuring gas generation while accelerating renewables, storage, and transmission to meet clean energy and carbon-neutral targets by 2045.
Key Points
A stop-gap policy to prevent blackouts by buying fossil power while fast-tracking renewables, storage, and grid upgrades.
✅ Temporary procurement of gas to avoid rolling blackouts
✅ Accelerates renewables, storage, transmission permitting
✅ Aims for carbon neutrality by 2045 without new gas plants
California wants to quit fossil fuels. Just not yet Faced with a fragile electrical grid and the prospect of summertime blackouts, the state agreed to put aside hundreds of millions of dollars to buy power from fossil fuel plants that are scheduled to shut down as soon as next year.
That has prompted a backlash from environmental groups and lawmakers who say Democratic Gov. Gavin Newsom’s approach could end up extending the life of gas plants that have been on-track to close for more than a decade and could threaten the state’s goal to be carbon neutral by 2045.
“The emphasis that the governor has been making is ‘We’re going to be Climate Leaders; we’re going to do 100 percent clean energy; we’re going to lead the nation and the world,’” said V. John White, executive director of the Sacramento-based Center for Energy Efficiency and Renewable Technologies, a non-profit group of environmental advocates and clean energy companies. “Yet, at least a part of this plan means going the opposite direction.”
That plan was a last-minute addition to the state’s energy budget, which lawmakers in the Democratic-controlled Legislature reluctantly passed. Backers say it’s necessary to avoid the rolling blackouts like the state experienced during a heat wave in 2020. Critics see a muddled strategy on energy, and not what they expected from a nationally ambitious governor who has made climate action a centerpiece of his agenda.
The legislation, which some Democrats labeled as “lousy” and “crappy,” reflects the reality of climate change. Heat waves are already straining power capacity, and the transition to cleaner energy isn’t coming fast enough to meet immediate needs in the nation’s most populous state.
Officials have warned that outages would be possible this summer, as the grid faces heat wave tests again, with as many as 3.75 million California homes losing power in a worst-case scenario of a West-wide heat wave and insufficient electrical supplies, particularly in the evenings.
It’s also an acknowledgment of the political reality that blackout politics are hazardous to elected officials, even in a state dominated by one party.
Newsom emphasized that the money to prop up the power grid, part of a larger $4.3 billion energy spending package, is meant as a stop-gap measure. The bill allows the Department of Water Resources to spend $2.2 billion on “new emergency and temporary generators, new storage systems, clean generation projects, and funding on extension of existing generation operations, if any occur,” the governor said in a statement after signing the bill.
“Action is needed now to maintain reliable energy service as the State accelerates the transition to clean energy,” Newsom said.
Following the signing, the governor called for the state California Air Resources Board to add a set of ambitious goals to its 2022 Scoping Plan, which lays out California’s path for reducing carbon emissions.
Among Newsom’s requested changes is a move away from fossil fuels, asking state agencies to prepare for an energy transition that avoids the need for new natural gas plants.
Alex Stack, a spokesman for the governor, said in a statement that California has been a global leader in reducing pollution and exporting energy policies across Western states, and pointed to Newsom’s recent letter to the Air Resources Board as well as one sent to President Joe Biden outlining how states can work with the federal government to combat climate change.
“California took action to streamline permitting for clean energy projects to accelerate the build out of clean energy that is needed to meet our climate goals and help maintain reliability in the face of extreme heat, wildfires, and drought,” Stack said.
But the prospect of using state money on fossil fuel power, even in the short term, has raised ire among the state’s many environmental advocacy groups, and raised questions about whether California will be able to achieve its goals.
“What is so frustrating about an energy bill like this is that we are at crunch time to meet these goals,” said Mary Creasman, CEO of California Environmental Voters. “And we’re investing a scale of funding into things that exacerbate those goals.”
Emmanuelle Chriqui and Mary Creasman speak during the 2021 Environmental Media Association IMPACT Summit at Pendry West Hollywood on September 2, 2021 in West Hollywood, California. | Jesse Grant/Getty Images for Environmental Media Association
With climate change-induced drought and high temperatures continuing to ravage the West, California anticipates the demand on the grid will only continue to grow. Despite more than a decade of bold posturing and efforts to transition to solar, wind and hydropower, the state worries it doesn’t have enough renewable energy sources on hand to keep the power on in an emergency right now, amid a looming shortage that will test reliability.
The specter of power outages poses a hazard to Newsom, and Democrats in general, especially ahead of November. While the governor is widely expected to sail to reelection, rolling blackouts are a serious political liability — in 2003, they were the catalyst for recalling Democratic Gov. Gray Davis. A lack of power isn’t just about people sweating in the dark, said Steven Maviglio, a longtime Democratic consultant who served as communications director for Davis, it can affect businesses, travel and have an outsized impact on the economy.
It behooves any state official to keep the power on, but, unlike Davis, Newsom is under serious pressure to make sure the state also adheres to its climate goals.
“Gavin Newsom’s brand is based on climate change and clean air, so it’s a little more difficult for him to say ‘well that’s not as important as keeping the power on,’” Maviglio said.
The same bill effectively ends local government control over those projects, for the time being. It hopes to speed up the state’s production of renewable energy sources by giving exclusive authority over the siting of those projects to a single state agency for the next seven years.
Environmental advocates say the state is now scrambling to address an issue they’ve long known was coming. In 2010, California officials set a schedule to retire a number of coastal gas plants that rely on what’s known as once-through cooling systems, which are damaging to the environment, especially marine life, even as regulators weigh more power plants to maintain reliability today. Many of those plants have been retired since 2010, but others have received extensions.
The remaining plants have various deadlines for when they must cease operations, with the soonest being the end of 2023.
Also at issue is the embattled Diablo Canyon nuclear power plant, California’s largest electricity source. The Pacific Gas & Electric-owned plant is scheduled to close in 2025, but the strain on the grid has officials considering the possibility of seeking an extension. Newsom said earlier this spring he would be open to extending the life of the plant. Doing so would also require federal approval.
Al Muratsuchi stands and talks into a microphone with a mask on.
Assemblyman Al Muratsuchi speaks during an Assembly session in Sacramento, Calif., on Jan. 31, 2022. | Rich Pedroncelli/AP Photo
The International Brotherhood of Electrical Workers 1245, a labor union, sees the energy package as a way to preserve Diablo Canyon, and jobs at the plant.
“The value to 1245 PG&E members at Diablo Canyon is clear — funding to keep the plant open,” the union said of the bill.
Assemblymember Al Muratsuchi (D-Los Angeles) criticized the bill as “crappy” when it came to the floor in late June, describing it as “a rushed, unvetted and fossil-fuel-heavy response” to the state’s need to bolster the grid.
“The state has had over 12 years to procure and bring online renewable energy generation to replace these once through cooling gas power plants,” Muratsuchi said. “Yet, the state has reneged on its promise to shut down these plants, not once, but twice already.”
Not all details of the state’s energy budget are final. Lawmakers still have $3.8 billion to allocate when they return on Aug. 1 for the final stretch of the year.
Creasman, at California Environmental Voters, said she wants lawmakers to set specific guidelines for how and where it will spend the $2.2 billion when they return in August to dole out the remaining money in the budget. Newsom and legislators also need to ensure that this is the last time California has to spend money on fossil fuel, she said.
“Californians deserve to see what the plan is to make sure we’re not in this position again of having to choose between making climate impacts worse or keeping our lights on,” Creasman said. “That’s a false choice.”
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Why the Texas grid causes the High Plains to turn off its wind turbines
Texas High Plains Wind Energy faces ERCOT transmission congestion, limiting turbines in the Panhandle from stabilizing the grid as gas prices surge, while battery storage and solar could enhance reliability and lower power bills statewide.
Key Points
A major Panhandle wind resource constrained by ERCOT transmission, impacting grid reliability and electricity rates.
✅ Over 11,000 turbines can power 9M homes in peak conditions
✅ Transmission congestion prevents flow to major load centers
✅ Storage and solar can bolster reliability and reduce bills
Texas’s High Plains region, which covers 41 counties in the Texas Panhandle and West Texas, is home to more than 11,000 wind turbines — the most in any area of the state.
The region could generate enough wind energy to power at least 9 million homes. Experts say the additional energy could help provide much-needed stability to the electric grid during high energy-demand summers like this one, and even lower the power bills of Texans in other parts of the state.
But a significant portion of the electricity produced in the High Plains stays there for a simple reason: It can’t be moved elsewhere. Despite the growing development of wind energy production in Texas, the state’s transmission network, reflecting broader grid integration challenges across the U.S., would need significant infrastructure upgrades to ship out the energy produced in the region.
“We’re at a moment when wind is at its peak production profile, but we see a lot of wind energy being curtailed or congested and not able to flow through to some of the higher-population areas,” said John Hensley, vice president for research and analytics at the American Clean Power Association. “Which is a loss for ratepayers and a loss for those energy consumers that now have to either face conserving energy or paying more for the energy they do use because they don’t have access to that lower-cost wind resource.”
And when the rest of the state is asked to conserve energy to help stabilize the grid, the High Plains has to turn off turbines to limit wind production it doesn’t need.
“Because there’s not enough transmission to move it where it’s needed, ERCOT has to throttle back the [wind] generators,” energy lawyer Michael Jewell said. “They actually tell the wind generators to stop generating electricity. It gets to the point where [wind farm operators] literally have to disengage the generators entirely and stop them from doing anything.”
Texans have already had a few energy scares this year amid scorching temperatures and high energy demand to keep homes cool. The Electric Reliability Council of Texas, which operates the state’s electrical grid, warned about drops in energy production twice last month and asked people across the state to lower their consumption to avoid an electricity emergency.
The energy supply issues have hit Texans’ wallets as well. Nearly half of Texas’ electricity is generated at power plants that run on the state’s most dominant energy source, natural gas, and its price has increased more than 200% since late February, causing elevated home utility bills.
Meanwhile, wind farms across the state account for nearly 21% of the state’s power generation. Combined with wind production near the Gulf of Mexico, Texas produced more than one-fourth of the nation’s wind-powered electric generation last year.
Wind energy is one of the lowest-priced energy sources because it is sold at fixed prices, turbines do not need fuel to run and the federal government provides subsidies. Texans who get their energy from wind farms in the High Plains region usually pay less for electricity than people in other areas of the state. But with the price of natural gas increasing from inflation, Jewell said areas where wind energy is not accessible have to depend on electricity that costs more.
“Other generation resources are more expensive than what [customers] would have gotten from the wind generators if they could move it,” Jewell said. “That is the definition of transmission congestion. Because you can’t move the cheaper electricity through the grid.”
A 2021 ERCOT report shows there have been increases in stability constraints for wind energy in recent years in both West and South Texas that have limited the long-distance transfer of power.
“The transmission constraints are such that energy can’t make it to the load centers. [High Plains wind power] might be able to make it to Lubbock, but it may not be able to make it to Dallas, Fort Worth, Houston or Austin,” Jewell said. “This is not an insignificant problem — it is costing Texans a lot of money.”
Some wind farms in the High Plains foresaw there would be a need for transmission. The Trent Wind Farm was one of the first in the region. Beginning operations in 2001, the wind farm is between Abilene and Sweetwater in West Texas and has about 100 wind turbines, which can supply power to 35,000 homes. Energy company American Electric Power built the site near a power transmission network and built a short transmission line, so the power generated there does go into the ERCOT system.
But Jewell said high energy demand and costs this summer show there’s a need to build additional transmission lines to move more wind energy produced in the High Plains to other areas of the state.
Jewell said the Public Utility Commission, which oversees the grid, is conducting tests to determine the economic benefits of adding transmission lines from the High Plains to the more than 52,000 miles of lines that already connect to the grid across the state. As of now, however, there is no official proposal to build new lines.
“It does take a lot of time to figure it out — you’re talking about a transmission line that’s going to be in service for 40 or 50 years, and it’s going to cost hundreds of millions of dollars,” Jewell said. “You want to be sure that the savings outweigh the costs, so it is a longer process. But we need more transmission in order to be able to move more energy. This state is growing by leaps and bounds.”
A report by the American Society of Civil Engineers released after the February 2021 winter storm stated that Texas has substantial and growing reliability and resilience problems with its electric system.
The report concluded that “the failures that caused overwhelming human and economic suffering during February will increase in frequency and duration due to legacy market design shortcomings, growing infrastructure interdependence, economic and population growth drivers, and aging equipment even if the frequency and severity of weather events remains unchanged.”
The report also stated that while transmission upgrades across the state have generally been made in a timely manner, it’s been challenging to add infrastructure where there has been rapid growth, like in the High Plains.
Despite some Texas lawmakers’ vocal opposition against wind and other forms of renewable energy, and policy shifts like a potential solar ITC extension can influence the wind market, the state has prime real estate for harnessing wind power because of its open plains, and farmers can put turbines on their land for financial relief.
This has led to a boom in wind farms, even with transmission issues, and nationwide renewable electricity surpassed coal in 2022 as deployment accelerated. Since 2010, wind energy generation in Texas has increased by 15%. This month, the Biden administration announced the Gulf of Mexico’s first offshore wind farms will be developed off the coasts of Texas and Louisiana and will produce enough energy to power around 3 million homes.
“Texas really does sort of stand head and shoulders above all other states when it comes to the actual amount of wind, solar and battery storage projects that are on the system,” Hensley said.
One of the issues often brought up with wind and solar farms is that they may not be able to produce as much energy as the state needs all of the time, though scientists are pursuing improvements to solar and wind to address variability. Earlier this month, when ERCOT asked consumers to conserve electricity, the agency listed low wind generation and cloud coverage in West Texas as factors contributing to a tight energy supply.
Hensley said this is where battery storage stations can help. According to the U.S. Energy Information Administration, utility-scale batteries tripled in capacity in 2021 and can now store up to 4.6 gigawatts of energy. Texas has been quickly developing storage projects, spurred by cheaper solar batteries, and in 2011, Texas had only 5 megawatts of battery storage capacity; by 2020, that had ballooned to 323.1 megawatts.
“Storage is the real game-changer because it can really help to mediate and control a lot of the intermittency issues that a lot of folks worry about when they think about wind and solar technology,” Hensley said. “So being able to capture a lot of that solar that comes right around noon to [1 p.m.] and move it to those evening periods when demand is at its highest, or even move strong wind resources from overnight to the early morning or afternoon hours.”
Storage technology can help, but Hensley said transmission is still the big factor to consider.
Solar is another resource that could help stabilize the grid. According to the Solar Energy Industries Association, Texas has about 13,947 megawatts of solar installed and more than 161,000 installations. That’s enough to power more than 1.6 million homes.
This month, the PUC formed a task force to develop a pilot program next year that would create a pathway for solar panels and batteries on small-scale systems, like homes and businesses, to add that energy to the grid, similar to a recent virtual power plant in Texas rollout. The program would make solar and batteries more accessible and affordable for customers, and it would pay customers to share their stored energy to the grid as well.
Hensley said Texas has the most clean-energy projects in the works that will likely continue to put the region above the rest when it comes to wind generation.
“So they’re already ahead, and it looks like they’re going to be even farther ahead six months or a year down the road,” he said.
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Electric cars don't need better batteries. America needs better charging networks
EV charging anxiety reflects concerns beyond range anxiety, focusing on charging infrastructure, fast chargers, and network reliability during road trips, from Tesla Superchargers to Electrify America stations across highways in the United States.
Key Points
EV charging anxiety is worry about finding reliable fast chargers on public networks, not just limited range.
✅ Non-Tesla networks vary in uptime and plug-and-charge reliability.
✅ Charging deserts complicate route planning on long highway stretches.
✅ Sync stops: align rest breaks with fast chargers to save time.
With electric cars, people often talk about "range anxiety," and how cars with bigger batteries and longer driving ranges will alleviate that. I just drove an electric car from New York City to Atlanta, a distance of about 950 miles, and it taught me something important. The problem really isn't range anxiety. It's anxiety around finding a convenient and working chargers on America's still-challenged EV charging networks today.
Back in 2019, I drove a Tesla Model S Long Range from New York City to Atlanta. It was a mostly uneventful trip, thanks to Tesla's nicely organized and well maintained network of fast chargers that can fill the batteries with an 80% charge in a half hour or less. Since then, I've wanted to try that trip again with an electric car that wasn't a Tesla, one that wouldn't have Tesla's unified charging network to rely on.
I got my chance with a Mercedes-Benz EQS 450+, a car that is as close to a direct competitor to the Tesla Model S as any. And while I made it to Atlanta without major incident, I encountered glitchy chargers, called the charging network's customer service twice, and experienced some serious charging anxiety during a long stretch of the Carolinas.
Long range
The EPA estimated range for the Tesla I drove in 2019 was 370 miles, and Tesla's latest models can go even further.
The EQS 450+ is officially estimated to go 350 miles on a charge, but I beat that handily without even trying. When I got into the car, its internal displays showed a range estimate of 446 miles. On my trip, the car couldn't stretch its legs quite that far, because I was driving almost entirely on highways at fairly high speeds, but by my calculations, I could have gone between 370 and 390 miles on a charge.
I was going to drive over the George Washington Bridge then down through New Jersey, Delaware, Virginia then North Carolina and South Carolina. I figured three charging stops would be needed and, strictly speaking, that was correct. The driving route laid out by the car's navigation system included three charging stops, but the on-board computers tended push things to the limit. At each stop, the battery would be drained to a little over 10% or so. (I learned later this is a setting I could adjust to be more conservative if I'd wanted.)
But I've driven enough electric cars to have some concerns. I use public chargers fairly often, and I know they're imperfect, and we need to fix these problems to build confidence. Sometimes they aren't working as well as they should. Sometimes they're just plain broken. And even if the car's navigation system is telling you that a charger is "available," that can change at any moment. Someone else can pull into the charging spot just a few seconds before you get there.
I've learned to be flexible and not push things to the limit.
On the first day, when I planned to drive from New York to Richmond, Virginia, no charging stop was called for until Spotsylvania, Virginia, a distance of nearly 300 miles. By that point, I had 16% charge left in the car's batteries which, by the car's own calculation, would have taken me another 60 miles.
As I sat and worked inside the Spotsylvania Town Centre mall I realized I'd been dumb. I had already stopped twice, at rest stops in New Jersey and Delaware. The Delaware stop, at the Biden Welcome Center, had EV fast chargers, as the American EV boom accelerates nationwide. I could have used one even though the car's navigation didn't suggest it.
Stopping without charging was a lost opportunity and it cost me time. If I'm going to stop to recharge myself why not recharge the car, too?
But that's the thing, though. A car can be designed to go 350 miles or more before needing to park whereas human beings are not. Elementary school math will tell you that at highway speeds, that's nearly six hours of driving all at once. We need bathrooms, beverages, food, and to just get out and move around once in a while. Sure, it's physically possible to sit in a car for longer than that in one go, but most people in need of speed will take an airplane, and a driver of an EQS, with a starting price just north of $100,000, can almost certainly afford the ticket.
I stopped for a charge in Virginia but realized I could have stopped sooner. I encountered a lot of other electric cars on the trip, including this Hyundai Ioniq 5 charging next to the Mercedes.
I vowed not to make that strategic error again. I was going to take back control. On the second day, I decided, I would choose when I needed to stop, and would look for conveniently located fast chargers so both the EQS and I could get refreshed at once. The EQS's navigation screen pinpointed available charging locations and their maximum charging speeds, so, if I saw an available charger, I could poke on the icon with my finger and add it onto my route.
For my first stop after leaving Richmond, I pulled into a rest stop in Hillsborough, North Carolina. It was only about 160 miles south from my hotel and I still had half of a full charge.
I sipped coffee and answered some emails while I waited at a counter. I figured I would take as long as I wanted and leave when I was ready with whatever additional electricity the car had gained in that time. In all, I was there about 45 minutes, but at least 15 minutes of that was used trying to get the charger to work. One of the chargers was simply not working at all, and, at another one, a call to Electrify America customer service -- the EV charging company owned by Volkswagen that, by coincidence, operated all the chargers I used on the trip -- I got a successful charging session going at last. (It was unclear what the issue was.)
That was the last and only time I successfully matched my own need to stop with the car's. I left with my battery 91% charged and 358 miles of range showing on the display. I would only need to stop once more on way to Atlanta and not for a long time.
Charging deserts
Then I began to notice something. As I drove through North Carolina and then South Carolina, the little markers on the map screen indicating available chargers became fewer and fewer. During some fairly long stretches there were none showing at all, highlighting how better grid coordination could improve coverage.
It wasn't an immediate concern, though. The EQS's navigation wasn't calling for me to a charge up again until I'd nearly reached the Georgia border. By that point I would have about 11% of my battery charge remaining. But I was getting nervous. Given how far it was between chargers my whole plan of "recharging the car when I recharge myself" had already fallen apart, the much-touted electric-car revolution notwithstanding. I had to leave the highway once to find a gas station to use the restroom and buy an iced tea. A while later, I stopped for lunch, a big plate of "Lexington Style BBQ" with black eyed peas and collard greens in Lexington, North Carolina. None of that involved charging because there no chargers around.
Fortunately, a charger came into sight on my map while I still had 31% charge remaining. I decided I would protect myself by stopping early. After another call to Electrify America customer service, I was able to get a nice, high-powered charging session on the second charger I tried. After about an hour I was off again with a nearly full battery.
I drove the last 150 miles to Atlanta, crossing the state line through gorgeous wetlands and stopping at the Georgia Welcome Center, with hardly a thought about batteries or charging or range.
But I was driving $105,000 Mercedes. What if I'd been driving something that cost less and that, while still going farther than a human would want to drive at a stretch, wouldn't go far enough to make that trip as easily, a real concern for those deciding if it's time to buy an electric car today. Obviously, people do it. One thing that surprised me on this trip, compared to the one in 2019, was the variety of fully electric vehicles I saw driving the same highways. There were Chevrolet Bolts, Audi E-Trons, Porsche Taycans, Hyundai Ioniqs, Kia EV6s and at least one other Mercedes EQS.
Americans are taking their electric cars out onto the highways, as the age of electric cars gathers pace nationwide. But it's still not as easy as it ought to be.
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More Electricity From Wind & Solar Than Nuclear For 1st Time In USA
U.S. Renewable Energy Share 2022 leads electricity generation trends, as wind and solar outpace nuclear and coal, per EIA data, with hydropower gains and grid growth highlighting rapid, sustainable capacity expansion nationwide.
Key Points
Renewables supplied over 25% of U.S. electricity in 2022, as wind and solar outpaced nuclear with double-digit growth.
✅ Renewables provided 25.52% of U.S. power Jan-Apr 2022.
✅ Wind and solar beat nuclear by 17.96% in April.
✅ Solar up 28.93%, wind up 24.25%; hydropower up 9.99%.
During the first four months of 2022, electrical generation by renewable energy sources accounted for over 25% of the nation’s electricity, projected to soon be about one-fourth as growth continues. In April alone, renewables hit a record April share of 29.3% — an all-time high.
And for the first time ever, the combination of just wind power and solar produce more electricity in April than the nation’s nuclear power plants — 17.96% more.
This is according to a SUN DAY Campaign analysis of data in EIA’s Electric Power Monthly report. The report also reveals that during the first third of this year, solar (including residential) generation climbed by 28.93%, while wind increased by 24.25%. Combined, solar and wind grew by 25.46% and accounted for more than one-sixth (16.67%) of U.S. electrical generation (wind: 12.24%, solar: 4.43%).
Hydropower also increased by 9.99% during the first four months of 2022. However, wind alone provided 70.89% more electricity than did hydropower. Together with contributions from geothermal and biomass, the mix of renewable energy sources expanded by 18.49%, and building on its second-most U.S. source in 2020 status helped underscore momentum as it provided about 25.5% of U.S. electricity during the first four months of 2022.
For the first third of the year, renewables surpassed coal and nuclear power by 26.13% and 37.80% respectively. In fact, electrical generation by coal declined by 3.94% compared to the same period in 2021 while nuclear dropped by 1.80%.
“Notwithstanding headwinds such as the COVID pandemic, grid access problems, and disruptions in global supply chains, solar and wind remain on a roll,” noted the SUN DAY Campaign’s executive director Ken Bossong. “Moreover, by surpassing nuclear power by ever greater margins, they illustrate the foolishness of trying to revive the soon-to-retire Diablo Canyon nuclear plant in California and the just-retired Palisades reactor in Michigan rather than focusing on accelerating renewables’ growth.”
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25.5% Of US Electricity Coming From Renewable Energy
US Renewable Energy Growth drives the US electricity mix as wind, solar, and hydropower rise while coal, natural gas, and nuclear decline, boosting market share month over month and year over year across the grid.
Key Points
US Renewable Energy Growth tracks rising wind, solar, and hydro shares in the mix as coal, gas, and nuclear decline.
✅ Wind and solar surpass nuclear in April share
✅ Renewables reach 29.3% of US electricity in April
✅ Coal and natural gas shares trend lower since 2020
Electricity generated by renewable energy sources continues to grow month over month and year over year in the United States. In April 2022, the share of US electricity coming from renewable energy was up to 29.3%, surpassing a record April level reported previously in national data. That was up from 24.8% in April 2020 and 25.7% in April 2021.
Looking at the first four months of the year, renewables provided 25.5% of US electricity, and were the second-most U.S. source in 2020 as well, while the figure for January–April 2020 was 21.7% and the figure for January–April 2021 was 22.5%.
Coal power (20.2% of US electricity) was down year over year in this time period (from 22% in January–April 2021), even as renewables surpassed coal in 2022 nationwide, but is admittedly still a bit higher than it was in January–April 2020 (16.8%).
Electricity from natural gas is also down year over year, but only very slightly (34.7% for both years). Though, it has dropped significantly since January–April 2020 (39.6%).
Electricity from nuclear power continued to take a steady, step-by-step tumble.
Wind & Solar Power Growth Strong
As reported earlier, April was the first month that wind and solar power provided more electricity than nuclear across the United States. Wind and solar power provided 21% of US electricity, while nuclear power provided 17.8% of US electricity (coal, incidentally, also provided 17.8% of US electricity, but wind and solar had provided more electricity than coal in some previous months as well).
Wind and solar power’s combined market share for the first four months of the year was up from just 14.6% in 2020 and 18.4% in 2021.
Looking at their growth year over year, you can see strong and continuous expansion of solar-provided electricity and wind-provided electricity, amid favorable government plans that have supported deployment.
Solar grew from 2.9% in January–April 2020 to 3.6%in January–April 2021 to, eventually, 4.4% in January–April 2022, with solar's 2022 share rising to 4.7% for the full year. Wind rose from 9.2% to 10.3% to 12.2%.
Together, wind and solar were up from 12.1% in January–April 2020 to 13.9% in January–April 2021, reflecting a surge in wind power within the U.S. electricity mix over this period, to 16.7% January–April 2022.
Hydropower (6.5%) is holding approximately the same position as the same period in 2021 (6.5%), but it is down a significant chunk from April 2020 (8.2%).
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Pickering nuclear station is closing as planned, despite calls for refurbishment
Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.
Key Points
Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.
✅ 14% of Ontario electricity supplied by Pickering now
✅ Natural gas use rises; grid emissions projected up 375%
✅ IESO warns gas phaseout by 2030 risks blackouts, costs
The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.
In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.
Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.
But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.
“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.
“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”
The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.
Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.
The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.
The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.
The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.
One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.
“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.
The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.
Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.
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NDP takes aim at approval of SaskPower 8 per cent rate hike
SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.
Key Points
An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.
✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023
✅ Panel-approved amid natural gas price surge and higher fuel costs
✅ Avg residential bill up about $5 per step; affordability concerns
The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.
The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.
“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”
But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.
She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.
“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”
The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.
“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”
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N.W.T. will encourage more residents to drive electric vehicles
Northwest Territories EV Charging Corridor aims to link the Alberta boundary to Yellowknife with Level 3 fast chargers and Level 2 stations, boosting electric vehicle adoption in cold climates, cutting GHG emissions, supporting zero-emission targets.
Key Points
A planned corridor of Level 3 and Level 2 chargers linking Alberta and Yellowknife to boost EV uptake and cut GHGs.
✅ Level 3 fast charger funded for Behchoko by spring 2024.
✅ Up to 72 Level 2 chargers funded across N.W.T. communities.
✅ Supports Canada ZEV targets and reduces fuel use and CO2e.
Electric vehicles are a rare sight in Canada's North, with challenges such as frigid winter temperatures and limited infrastructure across remote regions.
The Northwest Territories is hoping to change that.
The territorial government plans to develop a vehicle-charging corridor between the Alberta boundary and Yellowknife to encourage more residents to buy electric vehicles to reduce their carbon footprint.
"There will soon be a time in which not having electric charging stations along the highway will be equivalent to not having gas stations," said Robert Sexton, director of energy with the territory’s Department of Infrastructure.
"Even though it does seem right now that there’s limited uptake of electric vehicles and some of the barriers seem sort of insurmountable, we have to plan to start doing this, because in five years' time, it’ll be too late."
The federal government has committed to a mandatory 100 per cent zero-emission vehicle sales target by 2035 for all new light-duty vehicles, though in Manitoba reaching EV targets is not smooth so progress may vary. It has set interim targets for at least 20 per cent of sales by 2026 and 60 per cent by 2030.
A study commissioned by the N.W.T. government forecasts electric vehicles could account for 2.9 to 11.3 per cent of all annual car and small truck sales in the territory in 2030.
The study estimates the planned charging corridor, alongside electric vehicle purchasing incentives, could reduce greenhouse gas emissions by between 260 and 1,016 tonnes of carbon dioxide equivalent in that year.
Sexton said it will likely take a few years before the charging corridor is complete. As a start, the territory recently awarded up to $480,000 to the Northwest Territories Power Corporation to install a Level 3 electric vehicle charger in Behchoko.
The N.W.T. government projects the charging station will reduce gasoline use by 61,000 litres and decrease carbon dioxide equivalent by up to 140 tonnes per year. It is scheduled to be complete by the spring of 2024.
The federal government earlier this month announced $414,000, along with $56,000 in territorial funding, to install up to 72 primarily Level 2 electric vehicle charges in public places, streets, multi-unit residential buildings, workplaces, and facilities with light-duty vehicle fleets in the N.W.T. by March 2024, while in New Brunswick new fast-charging stations are planned on the Trans-Canada.
In Yukon, the territory has pledged to develop electric vehicle infrastructure in all road-accessible communities by 2027. It has already installed 12 electric vehicle chargers with seven more planned, and in N.L. a fast-charging network signals early progress as well.
Just a few people in the N.W.T. currently own electric vehicles, and in Atlantic Canada EV adoption lags as well.
Patricia and Ken Wray in Hay River have owned a Tesla Model 3 for three years. Comparing added electricity costs with savings on gasoline, Patricia estimates they spend 60 per cent less to keep the Tesla running compared to a gas-powered vehicle.
“I don’t mind driving past the gas station,” she said.
Despite some initial hesitation about how the car would perform in the winter, Wray said she hasn’t had any issues with her Tesla when it’s -40 C, although it does take longer to charge. She added it “really hugs the road” in snowy and icy conditions.
“People in the North need to understand these cars are marvellous in the winter,” she said.
Wray said while she and her husband drive their Tesla regularly, it’s not feasible to drive long distances across the territory. As the number of electric vehicle charge stations increases across the N.W.T., however, that could change.
“I’m just very, very happy to hear that charging infrastructure is now starting to be put in place," she said.
Andrew Robinson with the YK Care Share Co-op is more skeptical about the potential success of a long-distance charging corridor. He said while government support for electric vehicles is positive, he believes there's a more immediate need to focus on uptake within N.W.T. communities. He pointed to local taxi services as an example.
"It’s a long stretch," he said of the drive from Alberta, where EVs are a hot topic, to Yellowknife. "It’s 17 hours of hardcore driving and when you throw in having to recharge, anything that makes that longer, people are not going to be really into that.”
The car sharing service, which has a 2016 Chevy Spark dubbed “Sparky,” states on its website that a Level 2 charger can usually recharge a vehicle within six to eight hours while a Level 3 charger takes approximately half an hour, as faster charging options roll out in B.C. and beyond.
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Zero-emissions electricity by 2035 is possible
Canada Net-Zero Electricity 2035 aligns policy and investments with renewables, wind, solar, hydro, storage, and transmission to power electrification of EVs and heat pumps, guided by a stringent clean electricity standard and carbon pricing.
Key Points
A 2035 plan for a zero-emissions grid using renewables, storage and transmission to electrify transport and homes.
✅ Wind, solar, and hydro backed by battery storage and reservoirs
✅ Interprovincial transmission expands reliability and lowers costs
✅ Stringent clean electricity standard and full carbon pricing
By Tom Green
Senior Climate Policy Advisor
David Suzuki Foundation
Electric vehicles are making inroads in some areas of Canada. But as their numbers grow, will there be enough electrical power for them, and for all the buildings and the industries that are also switching to electricity?
Canada – along with the United States, the European Union and the United Kingdom – is committed to a “net-zero electricity grid by 2035 policy goal”. This target is consistent with the Paris Agreement’s ambition of staying below 1.5 C of global warming, compared with pre-industrial levels.
This target also gives countries their best chance of energy security, as laid out in landmark reports over the past year from the International Energy Agency and the Intergovernmental Panel on Climate Change. A new federal regulation in the form of a clean electricity standard is being developed, but will it be stringent enough to set us up for climate success and avoid dead ends?
Canada starts this work from a relatively low emissions-intensity grid, powered largely by hydroelectricity. However, some provinces such as Alberta, Saskatchewan, Nova Scotia and New Brunswick still have predominantly fossil fuel-powered electricity. Plus, there is a risk of more natural gas generation of electricity in the coming years in most provinces without new federal and provincial regulations.
This means the transition of Canada’s electricity system must solve two problems at once. It must first clean up the existing electricity system, but it must also meet future electricity needs from zero-emissions sources while overall electricity capacity doubles or even triples by 2050.
Canada has enormous potential for renewable generation, even though it remains a solar power laggard in deployment to date. Wind, solar and energy storage are proven, affordable technologies that can be produced here in Canada, while avoiding the volatility of global fossil fuel markets.
As wind and solar have become the cheapest forms of electricity generation in history, we’re already seeing foreign governments and utilities ramp up renewable projects at the pace and scale that would be needed here in Canada, highlighting a significant global electricity market opportunity for Canadian firms at home. In 2020, 280 gigawatts of new capacity was added globally – a 45 per cent increase over the previous year. In Canada, since 2010, annual growth in renewables has so far averaged less than three per cent.
So why aren’t we moving full steam – or electron – ahead? With countries around the world bringing in wind and solar for new generation, why is there so much delay and doubt in Canada, even as analyses explore why the U.S. grid isn’t 100% renewable and remaining barriers?
The modelling team drew on a dataset that accounts for how wind and solar potential varies across the country, through the weeks of the year and the hours of each day. The models provide solutions for the most cost-effective new generation, storage and transmission to add to the grid while ensuring electricity generation meets demand reliably every hour of the year.
The David Suzuki Foundation partnered with the University of Victoria to model the electricity grid of the future.
To better understand future electricity demand, a second modelling team was asked to explore a future when homes and businesses are aggressively electrified; fossil fuel furnaces and boilers are retired and replaced with electric heat pumps; and gasoline and diesel cars are replaced by electric vehicles and public transit. It also dialed up investments in energy efficiency to further reduce the need for energy. These hourly electricity-demand projections were fed back to the models developed at the University of Victoria.
The results? It is possible to meet Canada’s needs for clean electricity reliably and affordably through a focus on expanding wind and solar generation capacity, complemented with new transmission connections between provinces, and other grid improvements.
How is it that such high levels of variable wind and solar can be added to the grid while keeping the lights on 24/7? The model took full advantage of the country’s existing hydroelectric reservoirs, using them as giant batteries, storing water behind the dams when wind and solar generation was high to be used later when renewable generation is low, or when demand is particularly high. The model also invested in more transmission to enable expanded electricity trade between provinces and energy storage in the form of batteries to smooth out the supply of electricity.
Not only is it possible, but the renewable pathway is the safe bet.
There’s no doubt it will take unprecedented effort and scale to transform Canada’s electricity systems. The high electrification pathway would require an 18-fold increase over today’s renewable electricity capacity, deploying an unprecedented amount of new wind, solar and energy storage projects every year from now to 2050. Although the scale seems daunting, countries such as Germany are demonstrating that this pace and scale is possible.
The modelling also showed that small modular nuclear reactors (SMRs) are neither necessary nor cost-effective, making them a poor candidate for continued government subsidies. Likewise, we presented pathways with no need for continued fossil fuel generation with carbon capture and storage (CCS) – an expensive technology with a global track record of burning through public funds while allowing fossil fuel use to expand and while capturing a smaller proportion of the smokestack carbon than promised. We believe that Canada should terminate the significant subsidies and supports it is giving to fossil fuel companies and redirect this support to renewable electricity, energy efficiency and energy affordability programming.
The transition to clean electricity would come with new employment for people living in Canada. Building tomorrow’s grid will support more than 75,000 full-time jobs each year in construction, operation and maintenance of wind, solar and transmission facilities alone.
Regardless of the path chosen, all energy projects in Canada take place on unceded Indigenous territories or treaty land. Decolonizing power structures with benefits to Indigenous communities is imperative. Upholding Indigenous rights and title, ensuring ownership opportunities and decision-making and direct support for Indigenous communities are all essential in how this transition takes place.
Wind, solar, storage and smart grid technologies are evolving rapidly, but our understanding of the possibilities they offer for a zero-emissions future, including debates over clean energy’s dirty secret in some supply chains, appears to be lagging behind reality. As the Institut de L’énergie Trottier observed, decarbonization costs have fallen faster than modellers anticipated.
The shape of tomorrow’s grid will largely depend on policy decisions made today. It’s now up to people living in Canada and their elected representatives to create the right conditions for a renewable revolution that could make the country electric, connected and clean in the years ahead.
To avoid a costly dash-to-gas that will strand assets and to secure early emissions reductions, the electricity sector needs to be fully exposed to the carbon price. The federal government’s announcement that it will move forward with a clean electricity standard – requiring net-zero emissions in the electricity sector by 2035 – will help if the standard is stringent.
Federal funding to encourage provinces to expand interprovincial transmission, including recent grid modernization investments now underway will also move us ahead. At the provincial level, electricity system governance – from utility commission mandates to electricity markets design – needs to be reformed quickly to encourage investments in renewable generation. As fossil fuels are swapped out across the economy, more and more of a household’s total energy bill will come from a local electric utility, so a national energy poverty strategy focused on low-income and equity-seeking households must be a priority.
The payoff from this policy package? Plentiful, reliable, affordable electricity that brings better outcomes for community health and resilience while helping to avoid the worst impacts of climate change.
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Gravity power holds major promise for the decarbonization of electricity grids
Gravity Energy Storage converts raised-mass potential into grid power, enabling long-duration renewable energy storage with gravity batteries, pumped-hydro alternatives, and scalable systems in towers, mineshafts, and elevators to decarbonize electricity and balance intermittency.
Key Points
Stores electricity as lifted mass, then generates clean power by lowering weights to balance renewable grids.
✅ Uses towers, mineshafts, and elevators as gravity batteries
✅ Complements wind and solar with long-duration storage
✅ Lower LCOE than lithium-ion; fewer environmental impacts
The general workings of gravity are nothing new: What goes up must come down. Over the past decade, scientists have been pursuing a new approach to this force of nature, exploring how it can generate carbon-free electricity through what’s been dubbed as “gravity power.”
Let’s take the fabled story of Isaac Newton’s falling apple as an example, but give it a twist. Instead of there being an apple dangling above him, Newton takes an apple and lifts it above his head, giving that apple his energy. That energy is then stored in the apple until he drops it, when the force of gravity releases the energy in the form of motion as it falls to the ground.
Gravity-powered batteries reconfigure this concept on a much larger scale. Steve Taber, chairman and chief executive officer of Gravity Power, describes it as a game-changing technology. “[It’s] capable of decarbonizing the grid by 80 to 90 percent without raising costs for consumers and without damaging the environment,” he says of his California-based company.
So, could this cornerstone of modern physics help accelerate the transition to a sustainable future and support nations’ goals of achieving carbon neutrality by 2050?
How it works
Gravity has been used to power mechanical movement since Dutchman Christiaan Huygens invented the pendulum clock in the 1600s.
Modern-day gravity power involves raising a heavy object with a pump, crane or motor to create gravitational potential energy. When the same mass is lowered to its original height, it activates a generator that converts the kinetic energy into electricity. Using this principle, gravity power can now be generated from skyscraper elevators, decommissioned mineshafts, and the downhill momentum of electric trucks and trains, to name a few examples. The entire structures that support such operations are considered gravity batteries.
The concept is similar to pumped-storage hydro power stations – the first of which was built in Switzerland in 1907 – which pump water uphill and release it downhill into generators when electricity is needed.
However, storing pumped hydro energy requires large amounts of land, needs to be located near a water source, is not scalable once built, and often uses carbon-intensive materials that are harmful to the environment, according to Robert Piconi, chairman and CEO of Energy Vault, a Swiss-U.S. company that was founded in 2017 and has become one of the sector’s leaders, while natural gas pipe storage is being explored in Europe as another pathway.
“Energy Vault’s gravity-based solutions are founded on the well-understood physics and mechanical engineering fundamentals of pumped hydroelectric energy storage, but replace water with custom-made composite blocks that can be made from low-cost and locally sourced materials,” he says.
Anytime, anywhere
As solar and wind energies gain traction to replace fossil fuels such as coal, gas and oil, the full potential of both renewable energies has been hampered by a simple fact of nature: The sun doesn’t always shine or enable nighttime generation reliably, and the wind doesn’t always blow. This is where gravity power can fill a crucial niche. The beauty of this technology is that it can be harnessed at any time, is relatively cheap and is viable almost anywhere.
In fact, it is intended to complement rather than replace other renewable energies – so much so that it needs to be near a grid connection that supports renewable energy. When surplus renewable energy is stored, it is used to lift the heavy mass to its potential height. Then, when solar and wind sources are unable to deliver during peak periods of electricity use, the mass is lowered to its original position to generate energy.
Energy storage is fast becoming big business for investors – the global market is expected to attract about USD 620 billion in investment by 2040, according to BloombergNEF forecasts, while UK energy storage faces calls to start large-scale storage construction to meet net-zero targets. Currently, this segment is dominated by chemical batteries, with lithium-ion making up 93 percent of the energy storage technology mix in 2020, based on figures published by the International Energy Agency.
“[Gravity] technology responds to a key bottleneck in renewable energy–dominated power grids,” says Adriaan Korthuis, co-founder and managing partner of Climate Focus in Amsterdam. “Storage of electricity is a major challenge in our global transition to renewable energy.”
Cheaper and cleaner
Generating power through gravity is also much cheaper and cleaner than renewable energies that rely on chemical batteries for storage, while innovations such as advanced nuclear explore integrated molten-salt energy storage. At 6.5 cents per kilowatt hour, it costs less than half that of lithium-ion, which degrades over time and has a potentially severe environmental impact through mining and disposal, according to Gravity Power.
Based on the ‘levelized cost of energy’ – a standard benchmark that measures the total cost of running a facility divided by the electricity it is expected to produce over its lifetime – gravity power is much more cost-effective than pumped-storage hydro, hydrogen, power-flow and lithium-ion technologies, according to the company.
Grid-connected energy storage is needed in three categories: short duration (less than 1 hour) to regulate frequency; long duration (8 to 16 hours) for shifting from higher-emitting to lower-emitting power sources in a day, known as ‘intraday generation shifting’; and very long duration (days, weeks or seasons) for occasional periods when renewable energy underproduces, according to Taber.
“The wind and solar industries have grown rapidly because the buyers of power made long-term, fixed-price purchase agreements available,” Taber says. “A similar [purchasing] instrument will accelerate the addition of long-duration energy storage to the grid.”
Korthuis of Climate Focus assesses the technology with a more cautious tone.
“The obvious challenges of this technology, as with any technology in early stages of development, are in its possibilities to scale, and in energy loss when converting electricity to storage and from stored energy back to electricity,” he says.
Sustainable bricks
Energy Vault takes a different approach to gravity power by constructing towers the size of a 20-story building. It provides electricity through a 100 megawatt-per-hour crane-operated system run by artificial intelligence to generate kinetic energy when the grid requires additional supply. Composite bricks of local soil, mine tailings, coal ash and decommissioned wind turbine blades are used as weights, thereby repurposing material destined for landfills and avoiding the use of emissions-causing concrete.
The Lugano, Switzerland-based company has attracted investors such as Softbank (USD 110 million), Saudi Aramco and BHP, the world’s biggest mining company. Mining companies are able to profit from the technology by redeploying abandoned infrastructure of decommissioned mines and by diversifying their strategy as nations rapidly shift to renewable energies.
China Tianying, a publicly traded recycling company in China, has also committed USD 50 million to Energy Vault’s initial public offering and another USD 50 million for a license to use the technology, in a market where China’s electricity sector remain in flux.
“Following successful research and development, and proving our technology at demonstration scale, we are now commercializing and deploying our technology globally, beginning in China where we have broken ground on our first EVx gravity energy storage system, with additional near-term deployments planned in the U.S. and Australia,” says Piconi.
A 100-megawatt hour project with Energy Vault began in China in March 2022, as the country also pilots compressed-air generation projects at scale in select provinces. The company sees great potential for the technology’s uptake in emerging markets, such as China and India, which are among the world’s largest emitters of greenhouse gases.
The transition to renewable energy promises to gain momentum with the advent of this fledgling industry, whose leaders see few impediments to its widespread adoption besides access to enough land for their tall towers and subterranean shafts. Gravity may yet prove to be the missing link in the energy chain that boosts the potential of sun and wind to decarbonize the world’s electricity grids.
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Electricity users in Newfoundland have started paying for Muskrat Falls
Muskrat Falls rate mitigation offsets Newfoundland Power's rate stabilization decrease as NL Hydro begins cost recovery; Public Utilities Board approval enables collections while Labrador-Island Link nears commissioning, stabilizing electricity rates despite megaproject delays, overruns.
Key Points
Muskrat Falls rate mitigation is NL Hydro's cost recovery via power rates to stabilize bills as commissioning nears.
✅ Offsets 6.4% decrease with a 6.1% rate increase
✅ About 6% now funds NL Hydro's rate mitigation
✅ Collections begin as Labrador-Island Link nears commissioning
With their July electricity bill, Newfoundland Power customers have begun paying for Muskrat Falls, though a lump-sum credit was also announced to offset costs and bills haven't significantly increased — yet.
In a July newsletter, Newfoundland Power said electricity bills were set to decrease by 6.4 per cent as part of the annual rate stabilization adjustment, which reflects the cost of electricity generation.
Instead, that decrease has been offset by a 6.1 increase in electricity rates so Newfoundland and Labrador Hydro can begin recovering the cost of Muskrat Falls, with a $5.2-billion federal package also underpinning the project, the $13-billion hydroelectric megaproject that is billions over budget and years behind schedule.
That means for residential customers, electricity rates will decrease to 12.346 cents per kilowatt, though the basic customer charge will go up slightly from $15.81 to $15.83. According to an N.L. Hydro spokesperson, about six per cent of electricity bills will now go toward what it calls a "rate mitigation fund."
N.L. Hydro claims victory in Muskrat Falls arbitration dispute with Astaldi
Software troubles blamed for $260M Muskrat Falls cost increase, with N.L. power rates stable for now
The spokesperson said N.L. Hydro is expecting the rate increase to result in $43 million this year, according to a recent financial update from the energy corporation — a tiny fraction of the project's cost.
N.L. Hydro asked the Public Utilities Board to approve the rate increase, a process similar to Nova Scotia's recent 14% approval by its regulator, in May. In a letter, Energy, Industry and Technology Minister Andrew Parsons supported the increase, though he asked N.L. Hydro to keep electricity rates "as close to current levels as possible.
Province modifies order in council
Muskrat Falls is not yet fully online — largely due to software problems with the Labrador-Island Link transmission line — and an order in council dictated that ratepayers on the island of Newfoundland would not begin paying for the project until the project was fully commissioned.
The provincial government modified that order in council so N.L. Hydro can begin collecting costs associated with Muskrat Falls once the project is "nearing" commissioning.
In June, N.L. Hydro said the project was expected to finally be completed by the end of the year.
In an interview with CBC News, Progressive Conservative interim leader David Brazil said the decision to begin recovering the cost of Muskrat Falls from consumers should have been delayed.
"There was an opportunity here for people to get some reprieve when it came to their electricity bills and this administration chose not to do that, not to help the people while they're struggling," he said.
In a statement, Parsons said reducing the rate was not an option, and would have resulted in increased borrowing costs for Muskrat Falls.
"Reducing the rate for one year to have it increase significantly the following year is not consistent with rate mitigation and also places an increased financial burden on taxpayers one year from now," Parsons said.
Decision 'reasonable': Consumer advocate
Brazil said his party didn't know the payments from Muskrat Falls would start in July, and criticized the government for not being more transparent.
A person wearing a blue shirt and black blazer stands outside on a lawn.
N.L. consumer advocate Dennis Browne says it makes sense to begin recouping the cost of Muskrat Falls. (Garrett Barry/CBC)
Newfoundland and Labrador consumer advocate Dennis Browne said the decision to begin collecting costs from consumers was "reasonable."
"We're into a financial hole due to Muskrat Falls, and what has happened is in order to stabilize rates, we have gone into rate stabilization efforts," he said.
In February, the provincial and federal governments signed a complex agreement to shield ratepayers aimed at softening the worst of the financial impact from Muskrat Falls. Browne noted even with the agreement, the provincial government will have to pay hundreds of millions in order to stabilize electricity rates.
"Muskrat Falls would cost us $0.23 a kilowatt, and that is out of the range of affordability for most people, and that's why we're into rate mitigation," he said. "This was part of a rate mitigation effort, and I accepted it as part of that."
