Ashe has doubts about wind power

UK Energy Price Guarantee Cost forecasts from Cornwall Insight suggest an £89bn bill, tied to wholesale gas prices, OBR projections, and fiscal policy, to shield households amid the cost of living crisis.

Key Points

It is the projected government spend to cap household bills, driven by wholesale gas prices and OBR market forecasts.

✅ Base case: £89bn over two years, per Cornwall Insight

✅ Range: £72bn to £140bn, volatile wholesale gas costs

✅ Excludes 6-month business support estimated at £22bn-£48bn

Liz Truss’s intervention to freeze energy prices for households for two years is expected to cost the government £89bn, according to the first major costing of the policy by the sector’s leading consultancy.

The analysis from Cornwall Insight, seen exclusively by the Guardian, shows the prime minister’s plan to tackle the cost of living crisis could cost as much as £140bn in a worst-case scenario.

Truss announced in early September that the average annual bill for a typical household would be capped at £2,500 to protect consumers from the intensifying cost of living crisis amid high winter energy costs and a scheduled 80% rise in the cap to £3,549.

The ultimate cost of the policy is uncertain as it is highly dependent on the wholesale cost of gas, including UK natural gas prices which have soared since Russia’s invasion of Ukraine put a squeeze on already-volatile international markets. Ballpark projections had put the cost anywhere from £100bn to £150bn.

The Office for Budget Responsibility is expected to give its forecast for the bill when it provides its independent assessment of Kwasi Kwarteng’s medium-term fiscal plan, which the chancellor said on Tuesday would still happen on 23 November despite previous reports that it would be brought forward.

Cornwall Insight analysed projections of wholesale market moves to cost the intervention. In its base case scenario, analysts expect the policy to cost £89bn. That assumes the cost of supporting each household would be just over £1,000 in the first year, and about £2,000 in the second year.

The study’s authors said the wholesale price of gas would be influenced by energy demand, the severity of weather, “geo-political uncertainty” and prices for liquified natural gas as Europe seeks to refill storage facilities, which countries have rushed to fill up this winter but which could be relatively empty by next spring.

In the best-case outcome, the policy would cost £72bn, with some projections pointing to a 16% decrease in energy bills in April for households, while the “extreme high” outlook would see the government shell out £140bn to protect 29m UK households.

Gas prices are expected to push even higher if the Kremlin decides to completely cut off Russian gas exports into Europe.

Cornwall Insight’s projection does not include a separate six-month initiative to cap costs for companies, charities and public sector organisations, which is forecast to cost £22bn to £48bn.

The consultancy’s chief executive, Gareth Miller, said the £70bn range in its forecasts reflected “a febrile wholesale market continuing to be beset by geopolitical instability, sensitivity to demand, weather and infrastructure resilience”.

He said: “Fortune befriends the bold, but it also favours the prepared. The large uncertainties around commodity markets over the next two years means that the government could get lucky with costs coming out at the low end of the range, but the opposite could also be true.

“In each case, the government may find itself passengers to circumstances outside its control, having made policy that is a hostage to surprises, events and volatile factors. That’s a difficult position to be in.”

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The government has faced criticism, as some British MPs urge tighter limits on prices, that the policy is effectively a “blank cheque” and is not targeted at the most vulnerable in society.

Concerns over how Truss and Kwarteng intend to fund a series of measures, including the price guarantee, have spooked financial markets.

The EU, which has outlined possible gas price cap strategies in recent proposals, said last week it planned to cap the revenues of low-carbon electricity generators at €180 a megawatt hour, which is less than half current market prices. Truss has so far resisted calls to extend a levy on North Sea oil and gas operators to electricity generators, who have benefited from a link between gas and electricity prices in Britain.

Truss hopes to strike voluntary long-term deals with generators including Centrica and EDF, alongside the government’s Energy Security Bill measures, to bring down wholesale prices.

The Financial Times reported on Tuesday that the government has threatened companies with legislation to cap their revenues if voluntary deals cannot be agreed.

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Manitoba Hydro unpaid leave plan offers unpaid days off to curb workforce costs amid COVID-19, avoiding temporary layoffs and pay cuts, targeting $5.7M savings through executive, manager, and engineer participation, with union options under discussion.

Key Points

A cost-saving measure offering unpaid days off to avert layoffs and pay cuts, targeting $5.7M savings amid COVID-19.

✅ 3 unpaid days for executives, managers, engineers

✅ Targets $5.7M total; $1.4M from non-union staff

✅ Avoids about 240 layoffs over a four-month period

The Manitoba government's Crown energy utility is offering workers unpaid days off as an alternative to temporary layoffs or pay cuts, even as residential electricity use rises due to more working from home.

In an email to employees, Manitoba Hydro president Jay Grewal says executives, managers, and engineers will take three unpaid days off before the fiscal year ends next March.

She says similar options are being discussed with other employee groups, which are represented by unions, as the Saskatchewan COVID-19 crisis reshaped workforces across the Prairies.

The provincial government ordered Manitoba Hydro to reduce workforce costs during the COVID-19 pandemic, as some power operators considered on-site staffing plans, and at one point the utility said it was looking at 600 to 700 temporary layoffs.

The organization said it’s looking for targeted savings of $5.7 million, down from $11 million previously estimated, while peers like BC Hydro’s Site C began reporting COVID-19 updates.

A spokesperson for Manitoba Hydro said non-unionized staff taking three days of unpaid leave will save $1.4 million of the $5.7 million savings.

“Three days of unpaid leave for every employee would eliminate layoffs entirely,” the spokesperson said in an email. “For comparison, approximately 240 layoffs would have to occur over a four-month period, while measures like Alberta's worker transition fund aim to support displaced workers, to achieve savings of $4.3 million.”

Grewal says the unpaid days off were a preferred option among the executives, managers, and engineers in an industry that recently saw a Hydro One worker injury case.

She says unions representing the other workers have been asked to respond by next Wednesday.

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EU Nuclear Reactor Life Extension focuses on energy security, carbon-free electricity, and safety as ageing reactors face gas shortages, high power prices, and regulatory approvals across the UK and EU amid winter supply risks.

Key Points

EU Nuclear Reactor Life Extension is the policy to keep ageing reactors safely generating affordable, low-carbon power.

✅ Extends reactor operation via inspections and component upgrades

✅ Addresses gas shortages, price volatility, and winter supply risks

✅ Requires national regulator approval and cost-benefit analysis

Shaken by the loss of Russian natural gas since the invasion of Ukraine, European countries are questioning whether they can extend the lives of their ageing nuclear reactors to maintain the supply of affordable, carbon-free electricity needed for net-zero across the bloc — but national regulators, companies and governments disagree on how long the atomic plants can be safely kept running.

Europe avoided large-scale blackouts last winter despite losing its largest supplier of natural gas, and as Germany temporarily extended nuclear operations to bolster stability, but industry is still grappling with high electricity prices and concerns about supply.

Given warnings from the International Energy Agency that the coming winters will be particularly at risk from a global gas shortage, governments have turned their attention to another major energy source — even as some officials argue nuclear would do little to solve the gas issue in the near term — that would exacerbate the problem if it too is disrupted: Europe’s ageing fleet of nuclear power plants.

Nuclear accounts for nearly 10% of energy consumed in the European Union, with transport, industry, heating and cooling traditionally relying on coal, oil and natural gas.

Historically nuclear has provided about a quarter of EU electricity and 15% of British power, even as Germany shut down its last three nuclear plants recently, underscoring diverging national paths.

Taken together, the UK and EU have 109 nuclear reactors running, even as Europe is losing nuclear power in several markets, most of which were built in the 1970s and 1980s and were commissioned to last about 30 years.

That means 95 of those reactors — nearly 90% of the fleet — have passed or are nearing the end of their original lifespan, igniting debates over how long they can safely continue to be granted operating extensions, with some arguing it remains a needed nuclear option for climate goals despite age-related concerns.

Regulations differ across borders, with some countries such as Germany turning its back on nuclear despite an ongoing energy crisis, but life extension discussions are usually a once-a-decade affair involving physical inspections, cost/benefit estimates for replacing major worn-out parts, legislative amendments, and approval from the national nuclear safety authority.

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COVID-19 Electricity Demand Shift flattens New York's load curve, lowers peak demand, and reduces wholesale prices as NYISO operators balance the grid amid stay-at-home orders, rising residential usage, cheap natural gas, and constrained renewables.

Key Points

An industry-wide change in load patterns: flatter peaks, lower prices, and altered grid operations during lockdowns.

✅ NYISO operators sequestered to maintain reliable grid control

✅ Morning and evening peaks flatten; residential use rises mid-day

✅ Wholesale prices drop amid cheap natural gas and reduced demand

At his post 150 miles up the Hudson, Jon Sawyer watches as a stay-at-home New York City stirs itself with each new dawn in this era of covid-19.

He’s a manager in the system that dispatches electricity throughout New York state, keeping homes lit and hospitals functioning, work that is so essential that he, along with 36 colleagues, has been sequestered away from home and family for going on four weeks now, to avoid the disease, a step also considered for Ontario power staff during COVID-19 measures.

The hour between 7 a.m. and 8 a.m. once saw the city bounding to life. A sharp spike would erupt on the system’s computer screens. Not now. The disease is changing the rhythms of the city, and, as this U.S. grid explainer notes, you can see it in the flows of electricity.

Kids are not going to school, restaurants are not making breakfast for commuters, offices are not turning on the lights, and thousands if not millions of people are staying in bed later, putting off the morning cup of coffee and a warm shower.

Electricity demand in a city that has been shut down is running 18 percent lower at this weekday morning hour than on a typical spring morning, according to the New York Independent System Operator, Sawyer’s employer. As the sun rises in the sky, usage picks up, but it’s a slower, flatter curve.

Though the picture is starkest in New York, it’s happening across the country. Daytime electricity demand is falling, even accounting for the mild spring weather, and early-morning spikes are deflating, with similar patterns in Ontario electricity demand as people stay home. The wholesale price of electricity is falling, too, driven by both reduced demand and the historically low cost of natural gas.

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Falling demand will hit the companies that run the “merchant generators” hardest. These are the privately owned power plants that sell electricity to the utilities and account for about 57 percent of electricity generation nationwide.

Closed businesses have resulted in falling demand. Residential usage is up — about 15 percent among customers of Con Edison, which serves New York City and Westchester County — as workers and schoolchildren stay home, while in Canada Hydro One peak rates remain unchanged for self-isolating customers, but it’s spread out through the day. Home use does not compensate for locked-up restaurants, offices and factories. Or for the subway system, which on a pre-covid-19 day used as much electricity as Buffalo.

Hospitals are a different story: They consume twice as much energy per square foot as hotels, and lead schools and office buildings by an even greater margin. And their work couldn’t be more vital as they confront the novel coronavirus.

Knowing that, Sawyer said, puts the ordinary routines of his job, which rely on utility disaster planning, the things about it he usually takes for granted, into perspective.

“Keeping the lights on: It comes to the forefront a little more when you understand, ‘I’m going to be sequestered on site to do this job, it’s so critical,’” he said, speaking by phone from his office in East Greenbush, N.Y., where he has been living in a trailer, away from his family, since March 23.

As coronavirus hospitalizations in New York began to peak in April, emergency medicine physician Howard Greller recorded his reflections. (Whitney Leaming/The Washington Post)
Sawyer, 53, is a former submariner in the U.S. Navy, so he has experience when it comes to being isolated from friends and family for long periods. Many of his colleagues in isolation, who all volunteered for the duty, also are military veterans, and they’re familiar with the drill. Life in East Greenbush has advantages over a submarine — you can go outside and throw a football or Frisbee or walk or run the trail on the company campus reserved for the operators, and every day you can use FaceTime or Skype to talk with your family.

His wife understood, he said, though “of course it’s a sacrifice.” But she grasped the obligation he felt to be there with his colleagues and keep the power on.

“It’s a new world, it’s definitely an adjustment,” said Rich Dewey, the system’s CEO, noting that America’s electricity is safe for now. “But we’re not letting a little virus slow us down.”

There are 31 operators, two managers and four cooks and cleaners all divided between East Greenbush, which handles daytime traffic, and another installation just west of Albany in Guilderland, which works at night. The operators work 12-hour shifts every other day.

Computers recalibrate generation, statewide, to equal demand, digesting tens of thousands of data points, every six seconds. Other computers forecast the needs looking ahead 2½ hours. The operators monitor the computers and handle the “contingencies” that inevitably arise.

They dispatch the electricity along transmission lines ranging from 115,000 volts to 765,000 volts, much of it going from plants and dams in western and northern New York downstate toward the city and Long Island.

They always focus on: “What is the next worse thing that can happen, and how can we respond to that?” Sawyer said.

It’s the same shift and the same work they’ve always done, and that gives this moment an oddly normal feeling, he said. “There’s a routine to it that some of the people working at home now don’t have.”

Medical workers check in with them daily to monitor their physical health and mental condition. So far, there have been no dropouts.

Cheap oil doesn’t mean much when no one’s going anywhere

Statewide, the daily demand for electricity has fallen nearly 9 percent.

The distribution system in New England is looking at a 3 to 5 percent decline; the Mid-Atlantic states at 5 to 7 percent; Washington state at 10 percent; and California by nearly as much. In Texas, demand is down 2 percent, “but even there you’re still seeing drops in the early-morning hours,” said Travis Whalen, a utility analyst with S&P Global Platts.

In the huge operating system that embraces much of the middle of the country, usage has fallen more than 8 percent — and the slow morning surge doesn’t peak until noon.

In New York, there used to be a smaller evening spike, too (though starting from a higher load level than the one in the morning). But that’s almost impossible to see anymore because everyone isn’t coming home and turning on the lights and TV and maybe throwing a load in the laundry all at once. No one goes out, either, and the lights aren’t so bright on Broadway.

California, in contrast, had a bigger spike in the evening than in the morning before covid-19 hit; maybe some of that had to do with the large number of early risers spreading out the morning demand and highlighting electricity inequality that shapes access. Both spikes have flattened but are still detectable, and the evening rise is still the larger.

Only at midnight, in New York and elsewhere, does the load resemble what it used to look like.

The wholesale price of electricity has fallen about 40 percent in the past month, according to a study by S&P Global Platts. In California it’s down about 30 percent. In a section covered by the Southwest Power Pool, the price is down 40 percent from a year ago, and in Indiana, electricity sold to utilities is cheaper than it has been in six years.

Some of the merchant generators “are going to be facing some rather large losses,” said Manan Ahuja, also an analyst with S&P Global Platts. With gas so cheap, coal has built up until stockpiles average a 90-day supply, which is unusually large. Ahuja said he believes renewable generators of electricity will be especially vulnerable because as demand slackens it’s easier for operators to fine-tune the output from traditional power plants.

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As Dewey put it, speaking of solar and wind generators, “You can dispatch them down but you can’t dispatch them up. You can’t make the wind blow or the sun shine.”

Jason Tundermann, a vice president at Level 10 Energy, which promotes renewables, argued that before the morning and evening spikes flattened they were particularly profitable for fossil fuel plants. He suggested electricity demand will certainly pick up again. But an issue for renewable projects under development is that supply chain disruptions could cause them to miss tax credit deadlines.

With demand “on pause,” as Sawyer put it, and consumption more evenly spread through the day, the control room operators in East Greenbush have a somewhat different set of challenges. The main one, he said, is to be sure not to let those high-voltage transmission lines overload. Nuclear power shows up as a steady constant on the real-time dashboard; hydropower is much more up and down, depending on the capacity of transmission lines from the far northern and western parts of the state.

Some human habits are more reliably fixed. The wastewater that moves through New York City’s sewers — at a considerably slower pace than the electricity in the nearby wires — hasn’t shown any change in rhythm since the coronavirus struck, according to Edward Timbers, a spokesman for the city’s Department of Environmental Protection. People may be sleeping a little later, but the “big flush” still arrives at the wastewater treatment plants, about three hours or so downstream from the typical home or apartment, every day in the late morning, just as it always has.
 

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UK Coal Phase-Out marks record-low coal generation as the UK grid shifts to renewable power, wind farms, and a net zero trajectory, slashing carbon emissions and supporting cleaner EV charging across the electricity system.

Key Points

UK Coal Phase-Out ends coal-fired electricity nationwide, powered by renewables and net zero policy to cut grid carbon.

✅ Coal's Q2 share fell to 0.7%, a record low

✅ Renewables up 12% with Beatrice wind farm

✅ EV charging grows cleaner as grid decarbonizes

The share of coal in the UK’s electricity system has fallen to record lows in recent months, alongside a coal-free power record, according to government data.

The figures show electricity generated by the UK’s most polluting power plants made up an average of 0.7% of the total in the second quarter of this year, a shift underway since wind first outpaced coal in 2016 across the UK. The amount of coal used to power the electricity grid fell by almost two-thirds compared with the same months last year.

A government spokesperson said coal-generated energy “will soon be a distant memory” as the UK moves towards becoming a net zero emissions economy, despite signs that low-carbon generation stalled in 2019 in some analyses.

“This new record low is a result of our world-leading low-carbon energy industry, which provided more than half of our energy last year and continues to go from strength to strength as we aim to end our contribution to climate change entirely by 2050,” the spokesperson said.

The UK electricity market is on track to end coal power after 142 years by the government’s target date of 2025.

This year three major energy companies have announced plans to close coal-fired power plants in the UK, which would leave only four remaining after the coming winter, ahead of the last coal power station going offline nationwide.

RWE said this month it would close the Aberthaw B power station in south Wales, its last UK coal plant, after the winter. SSE will close the Fiddler’s Ferry plant near Warrington, Cheshire, in March 2020, and EDF Energy will shutter the Cottam coal plant in September.

So far this year the UK has gone more than 3,000 hours without using coal for power, including a full week without coal earlier in the year – nearly five times more than the whole of 2017.

Meanwhile, the government’s data shows that renewable energy climbed by 12% from the second quarter of last year, boosted by the startup of the Beatrice windfarm in the Moray Firth in Scotland, and the UK leading the G20 in wind power share in recent assessments.

The cleaner power system could accelerate carbon savings from the UK’s roads, too, as more drivers opt for electric vehicles. A study by Imperial College London for the energy company Drax found that the UK’s increasingly low-carbon energy system meant electric cars were a greener option even when taking into account the carbon emissions produced by making car batteries.

Dr Iain Staffell, of Imperial College London, said: “An electric vehicle in the UK simply cannot be more polluting than its petrol or diesel equivalent – even when taking into account the upfront carbon cost of manufacturing their batteries. Any EV bought today could be emitting just a tenth of what a petrol car would in as little as five years’ time, as the electricity it uses to charge comes from an increasingly low-carbon mix.”

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Minnesota Electric Cooperatives are driving grid innovation with smart meters, time-of-use pricing, demand response, and energy storage, including iron-air batteries, to manage peak loads, integrate wind and solar, and cut costs for rural members.

Key Points

Member-owned utilities piloting load management, meters, and storage to integrate wind and solar, cutting peak demand.

✅ Time-of-use pricing pilots lower bills and shift peak load.

✅ Iron-air battery tests add multi-day, low-cost energy storage.

✅ Smart meters enable demand response across rural co-ops.

Minnesota electric cooperatives have quietly emerged as laboratories for clean grid innovation, outpacing investor-owned utilities on smart meter installations, time-based pricing pilots, and experimental battery storage solutions.

“Co-ops have innovation in their DNA,” said David Ranallo, a spokesperson for Great River Energy, a generation and distribution cooperative that supplies power to 28 member utilities — making it one of the state’s largest co-op players.

Minnesota farmers helped pioneer the electric co-op model more than a century ago, similar to modern community-generated green electricity initiatives, pooling resources to build power lines, transformers and other equipment to deliver power to rural parts of the state. Today, 44 member-owned electric co-ops serve about 1.7 million rural and suburban customers and supply almost a quarter of the state’s electricity.

Co-op utilities have by many measures lagged on clean energy. Many still rely on electricity from coal-fired power plants. They’ve used political clout with rural lawmakers to oppose new pollution regulations and climate legislation, and some have tried to levy steep fees on customers who install solar panels.

Where they are emerging as innovators is with new models and technology for managing electric grid loads — from load-shifting water heaters to a giant experimental battery made of iron. The programs are saving customers money by delaying the need for expensive new infrastructure, and also showing ways to unlock more value from cheap but variable wind and solar power.

Unlike investor-owned utilities, “we have no incentive to invest in new generation,” said Darrick Moe, executive director of the Minnesota Rural Electric Association. Curbing peak energy demand has a direct financial benefit for members.

Minnesota electric cooperatives have launched dozens of programs, such as the South Metro solar project, in recent years aimed at reducing energy use and peak loads, in particular. They include:

Cost calculations are the primary driver for electric cooperatives’ recent experimentation, and a lighter regulatory structure and evolving electricity market reforms have allowed them to act more quickly than for-profit utilities.

“Co-ops and [municipal utilities] can act a lot more nimbly compared to investor-owned utilities … which have to go through years of proceedings and discussions about cost-recovery,” said Gabe Chan, a University of Minnesota associate professor who has researched electric co-ops extensively. Often, approval from a local board is all that’s required to launch a venture.

Great River Energy’s programs, which are rebranded and sold through member co-ops, yielded more than 101 million kilowatt-hours of savings last year — enough to power 9,500 homes for a year.

Beyond lowering costs for participants and customers at large, the energy-saving and behavior-changing programs sometimes end up being cited as case studies by larger utilities considering similar offerings. Advocates supporting a proposal by the city of Minneapolis and CenterPoint Energy to allow residents to pay for energy efficiency improvements on their utility bills through distributed energy rebates used several examples from cooperatives.

Despite the pace of innovation on load management, electric cooperatives have been relatively slow to transition from coal-fired power. More than half of Great River Energy’s electricity came from coal last year, and Dairyland Power, another major power wholesaler for Minnesota co-ops, generated 70% of its energy from coal. Meanwhile, Xcel Energy, the state’s largest investor-owned utility, has already reduced coal to about 20% of its energy mix.

The transition to cleaner power for some co-ops has been slowed by long-term contracts with power suppliers that have locked them into dirty power. Others have also been stalled by management or boards that have been resistant to change. John Farrell, director of the Institute for Local Self-Reliance’s Energy Democracy program, said generalizing co-ops is difficult. 

“We’ve seen some co-ops that have got 75-year contracts for coal, that are invested in coal mines and using their newsletter to deny climate change,” he said. “Then you see a lot of them doing really amazing things like creating energy storage systems … and load balancing [programs], because they are unique and locally managed and can have that freedom to experiment without having to go through a regulatory process.”

Great River Energy, for its part, says it intends to reach 54% renewable generation by 2025, while some communities, like Frisco, Colorado, are targeting 100% clean electricity by specific dates. Its members recently voted to sell North Dakota’s largest coal plant, but the arrangement involves members continuing to buy power from the new owners for another decade.

The cooperative’s path to clean power could become clearer if its experimental iron-air battery project is successful. The project, the first of its kind in the country, is expected to be completed by 2023.

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