Gore urges civil disobedience to stop coal plants

Great Britain electricity generation spans renewables and baseload: wind, solar, nuclear, gas, and biomass, supported by National Grid interconnectors, embedded energy estimates, and BMRS data for dynamic imports and exports across Europe.

Key Points

A diverse, weather-driven mix of renewables, gas, nuclear, and imports coordinated by National Grid.

✅ Baseload from nuclear and biomass; intermittent wind and solar

✅ Interconnectors trade zero carbon imports via subsea cables

✅ Data from BMRS and ESO covers embedded energy estimates

Great Britain has one of the most diverse ranges of electricity generation in Europe, with everything from windfarms off the coast of Scotland to a nuclear power station in Suffolk tasked with keeping the lights on. The increasing reliance on renewable energy sources, as part of the country’s green ambitions, also means there can be rapid shifts in the main source of electricity generation. On windy days, most electricity generation comes from record wind generation across onshore and offshore windfarms. When conditions are cold and still, gas-fired power stations known as peaking plants are called into action.

The electricity system in Great Britain relies on a combination of “baseload” power – from stable generators such as nuclear and biomass plants – and “intermittent” sources, such as wind and solar farms that need the right weather conditions to feed energy into the grid. National Grid also imports energy from overseas, through subsea cables known as interconnectors that link to France, Belgium, Norway and the Netherlands. They allow companies to trade excess power, such as renewable energy created by the sun, wind and water, between different countries. By 2030 it is hoped that 90% of the energy imported by interconnectors will be from zero carbon energy sources, though low-carbon electricity generation stalled in 2019 for the UK.

The technology behind Great Britain’s power generation has evolved significantly over the last century, and at times wind has been the main source of electricity. The first integrated national grid in the world was formed in 1935 linking seven regions of the UK. In the aftermath of industrialisation, coal provided the vast majority of power, before oil began to play an increasingly important part in the 1950s. In 1956, the world’s first commercial nuclear reactor, Calder Hall 1 at Windscale (later Sellafield), was opened by Queen Elizabeth II. Coal use fell significantly in the 1990s while the use of combined cycle gas turbines grew, and in 2016 wind generated more electricity than coal for the first time. Now a combination of gas, wind, nuclear and biomass provide the bulk of Great Britain’s energy, with smaller sources such as solar and hydroelectric power also used. From October 2024, coal will no longer be used to generate electricity, following coal-free power records set in recent years.

Energy generation data is fetched from the Balancing Mechanism Reporting Service public feed, provided by Elexon – which runs the wholesale energy market – and is updated every five minutes, covering periods when wind led the power mix as well.

Elexon’s data does not include embedded energy, which is unmetered and therefore invisible to Great Britain’s National Grid. Embedded energy comprises all solar energy and wind energy generated from non-metered turbines. To account for these figures we use embedded energy estimates from the National Grid electricity system operator, which are published every 30 minutes.

Import figures refer to the net flow of electricity from the interconnectors with Europe and with Northern Ireland. A positive value represents import into the GB transmission system, while a negative value represents an export.

Hydro figures combine renewable run-of-the-river hydropower and pumped storage.

Biomass figures include Elexon’s “other” category, which comprises coal-to-biomass conversions and biomass combined heat and power plants.

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Goreway Power Station Overbilling exposed by Ontario Energy Board shows IESO oversight failures, GCG gaming, and $100M in inappropriate payments at the Brampton natural gas plant, penalized with fines and repayments impacting Ontario ratepayers.

Key Points

Goreway exploited IESO GCG flaws, causing about $100M in improper payouts and fines.

✅ OEB probe flagged $89M in ineligible start-up O&M charges

✅ IESO fined Goreway $10M; majority of excess costs recovered

✅ Audit found $200M in overbilling across nine generators

Hydro customers shelled out about $100 million in "inappropriate" payments to a natural gas plant that exploited flaws in how Ontario manages its private electricity generators, according to the Ontario Energy Board.

The company operating the Goreway Power Station in Brampton "gamed" the system for at least three years, according to an investigation by the provincial energy regulator. 

The investigation also delivers stinging criticism of the provincial government's Independent Electricity System Operator (IESO), slamming it for a lack of oversight. The probe by the Ontario Energy Board's market surveillance panel was completed nearly a year ago, but was only made public in November because it was buried on its website without a news release. CBC News is the first media outlet to report on the investigation.  

The excess payments to Goreway Power Station included:

• $89 million in ineligible expenses billed as the costs of firing up power production. 
• $5.6 million paid in three months from a flaw in how IESO calculated top-ups for the company committing to generate power a day in advance.   
• Of $11.2 million paid to compensate the company for IESO ordering it to start or stop generating power, the investigation concluded "a substantial portion ... was the result of gaming."  

Most privately-owned natural gas-fired plants in the province do not generate electricity constantly, but start and stop production in response to fluctuating market demand, even as the energy minister has requested an halt to natural gas generation across the grid.  IESO pays them a premium for the costs of firing up production, through what it calls "generation cost guarantee" programs. 

But the investigation found IESO did little checking into the details of Goreway Power Station's billings. 

Goreway Power Station, located near Highway 407 in Brampton, Ont., is an 875 megawatt natural gas power plant. (Goreway)

"Conservatively, at least $89 million of Goreway's submissions were clearly ineligible by any reasonable measure," concludes the report.

"Goreway routinely submitted what were obviously inappropriate expenses to be reimbursed by the IESO, and ultimately borne by Ontario ratepayers,"

The investigation panel found an "extraordinary pattern" to these billings by Goreway Power Station, suggesting the IESO should have caught on sooner. The company submitted more than $100 million in start-up operating and maintenance costs during the three-year period investigated — more than all other gas-fired generators in the province combined. The company's costs per start-up were more than double the next most expensive power generator. 

"Goreway repeatedly exploited defects in the GCG (generation cost guarantee) program, and in doing so received at least $89 million in gamed GCG payments." 

Company fined $10M

The investigation covered a three-year period from when Goreway Power Station began generating power in June 2009. Investigators said that delays in releasing documents slowed down their probe, and they only obtained all the records they needed in April 2016.

The investigating panel does not have the power to impose penalties on companies it found broke the rules. 

The IESO fined Goreway Power Station $10 million. The company has also repaid IESO "a substantial portion" of the excess payments it received during its first six years of operating, but the exact figure is blacked out in the investigation report that was made public. 

The control room from which the provincial government's Independent Electricity System Operator manages Ontario's power supply. The agency is also responsible for managing contracts with private power producers.(IESO)

"Goreway does not agree with many of the draft report's findings and conclusions, including any suggestion that Goreway engaged in gaming or that it deliberately misled the IESO," writes lawyer George Vegh on behalf of the company in a response to the investigation report, dated Aug. 1.

"Goreway has implemented initiatives designed to ensure that compliance is a chief operating principle."     

The power station, located near Highway 407 in Brampton, is a joint venture between Toyota Tsusho Corp. and JERA Co. Inc. During the period under scrutiny, the project was run by Toyota Tsusho and Chubu Electric Power Inc., both headquartered in Japan. 

Investigators fear 'same situation' exists today

The report blames the provincially-controlled IESO for creating a system with defects that allowed the over-billing. 

"Goreway was able to — and repeatedly did — exploit these defects," says the investigation report. It goes on to explain the flaws "have created opportunities for exploitation, to the serious financial disadvantage of Ontario's ratepayers," even as greening Ontario's grid could entail massive costs.

The investigation suggests IESO hasn't made adequate changes to ensure it won't happen again, at a time when an analysis of a dirtier grid is raising concerns.   

"Goreway stands as a clear example of how generators are able to exploit the generation costs guarantee regime," says the report.

"The Panel is concerned that the same situation remains in place today." 

PC energy critic Todd Smith raised CBC News' report on the Goreway Power Station in Tuesday's question period. (Ontario Legislature)

After CBC News broke the story Tuesday, the provincial government was forced to respond in question period, amid a broader push for new gas plants to boost electricity production. 

"Here we have yet another gas plant scandal in Peel region that's costing electricity customers over $100 million," said PC energy critic Todd Smith. He slammed "the incompetence of a government that once again failed to look out for electricity customers." 

Economic Development Minister Brad Duguid said: "There is no excuse for any company in this province to ever game the system."

Nine companies overbilled $200M: audit 

The IESO found out about the overbilling "some time ago," said Duguid.

"They fully investigated, they've recovered most of the cost, they delivered a $10 million fine — the biggest fine on record."

The program that Goreway exploited became the subject of an audit that the IESO launched in 2011. The agency uncovered $200 million in ineligible billings by nine power producers, wrote the IESO vice president for policy Terry Young in an email to CBC News.

The IESO has recovered up to 85 per cent of those ineligible costs, Young noted.

Reforms to the design of the the program have removed the potential for overpayments and made it more efficient, he said, even as Ontario weighs embracing clean power more broadly. Last year, its total annual costs dropped to $23 million, down from $61 million in 2014.

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B.C. EV Electrification 2055 projects grid capacity needs doubling to 37 GW, driven by electric vehicles, renewable energy expansion, wind and solar generation, limited natural gas, and policy mandates for zero-emission transportation.

Key Points

A projection that electrifying all B.C. road transport by 2055 would more than double grid demand to 37 GW.

✅ Site C adds 1.1 GW; rest from wind, solar, limited natural gas.

✅ Electricity price per kWh rises 9%, but fuel savings offset.

✅ Significant GHG cuts with 93% renewable grid under Clean Energy Act.

Researchers at the University of Victoria say that if B.C. were to shift to electric power for all road vehicles by 2055, the province would require more than double the electricity now being generated.

The findings are included in a study to be published in the November issue of the Applied Energy journal.

According to co-author and UVic professor Curran Crawford, the team at the university's Pacific Institute for Climate Solutions took B.C.'s 2015 electrical capacity of 15.6 gigawatts as a baseline, and added projected demands from population and economic growth, then added the increase that shifting to electric vehicles would require, while acknowledging power supply challenges that could arise.

They calculated the demand in 2055 would amount to 37 gigawatts, more than double 15.6 gigawatts used in 2015 as a baseline, and utilities warn of a potential EV charging bottleneck if demand ramps up faster than infrastructure.

"We wanted to understand what the electricity requirements are if you want to do that," he said. "It's possible — it would take some policy direction."

B.C. announces $4M in rebates for home and work EV charging stations across the province
The team took the planned Site C dam project into account, but that would only add 1.1 gigawatts of power. So assuming no other hydroelectric dams are planned, the remainder would likely have to come from wind and solar projects and some natural gas.

"Geothermal and biomass were also in the model," said Crawford, adding that they are more expensive electricity sources. "The model we were using, essentially, we're looking for the cheapest options."
Wind turbines on the Tantramar Marsh between Nova Scotia and New Brunswick tower over the Trans-Canada Highway. If British Columbia were to shift to 100 per cent electric-powered ground transportation by 2055, the province would have to significantly increase its wind and solar power generation. (Eric Woolliscroft/CBC)
The electricity bill, per kilowatt hour, would increase by nine per cent, according to the team's research, but Crawford said getting rid of the gasoline and diesel now used to fuel vehicles could amount to an overall cost saving, especially when combined with zero-emission vehicle incentives available to consumers.

The province introduced a law this year requiring that all new light-duty vehicles sold in B.C. be zero emission by 2040, while the federal 2035 EV mandate adds another policy signal, so the researchers figured 2055 was a reasonable date to imagine all vehicles on the road to be electric.

Crawford said hydrogen-powered vehicles weren't considered in the study, as the model used was already complicated enough, but hydrogen fuel would actually require more electricity for the electrolysis, when compared to energy stored in batteries.

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The study also found that shifting to all-electric ground transportation in B.C. would also mean a significant decrease in greenhouse gas emissions, assuming the Clean Energy Act remains in place, which mandates that 93 per cent of grid electricity must come from renewable resources, whereas nationally, about 18 per cent of electricity still comes from fossil fuels, according to 2019 data. 

"Doing the electrification makes some sense — If you're thinking of spending some money to reduce carbon emissions, this is a pretty cost effective way of doing that," said Crawford.

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EDF Nuclear Power Price Deal sets a 70 euros/MWh reference price, adds consumer protection if wholesale electricity prices exceed 110 euros/MWh, and outlines taxation mechanisms to shield bills while funding nuclear investment.

Key Points

A government-EDF deal setting 70 euros/MWh with safeguards above 110 euros/MWh to protect consumers.

✅ Reference price fixed at 70 euros/MWh, near EDF costs.

✅ Consumer shield above 110 euros/MWh; up to 90% extra-revenue tax.

✅ Review clauses maintain 70 euros/MWh through market swings.

State-controlled power group EDF and the French government have reached a tentative deal on future nuclear power prices, echoing a new electricity pricing scheme France has floated, a source close to the government said on Monday, ending months of tense negotiations.

The two sides agreed on 70 euros per megawatt hour (MWH) as a reference level for power prices, aligning with EU plans for more fixed-price contracts for consumers, the source said, cautioning that details of the deal are still being finalised.

The negotiations aimed to find a compromise between EDF, which is eager to maximise revenues to fund investments, and the government, keen to keep electricity bills for French households and businesses as low as possible, amid ongoing EU electricity reform debates across the bloc.

EDF declined to comment.

The preliminary deal sets out mechanisms that would protect consumers if power market prices rise above 110 euros/MWH, similar to potential emergency electricity measures being weighed in Europe, the source said, adding that the deal also includes clauses that would provide a price guarantee for EDF.

The 70 euros/MWH agreed reference price level is close to EDF's nuclear production costs, as Europe moves to revamp its electricity market more broadly. The nuclear power produced by the company provides 70% of France's electricity.

The agreement would allow the government to tax EDF's extra revenues at 90% if prices surpass 110 euros/MWH, in order to offset the impact on consumers. It would also enable a review of conditions in case of market fluctuations to safeguard the 70 euro level for EDF, reflecting how rolling back electricity prices is tougher than it appears, the source said.

French wholesale electricity prices are still above 100 euros/MWH, after climbing to 1,200 euros during last year's energy crisis, even as diesel prices have returned to pre-conflict levels.

A final agreement should be officially announced on Tuesday after a meeting between Finance Minister Bruno Le Maire, Energy Transition Minister Agnes Pannier-Runacher and EDF chief Luc Remont.

That meeting will work out the final details on price thresholds and tax rates between the reference level and the upper limit, the source said.

Negotiations between the two sides were so fraught that at one stage they raised questions about the future of EDF chief Luc Remont, who was appointed by President Emmanuel Macron a year ago to turn around EDF.

The group ended 2022 with a 18 billion-euro loss and almost 65 billion euros of net debt, hurt by a record number of reactor outages that coincided with soaring energy prices in the wake of Russia's invasion of Ukraine.

With its output at a 30-year low, EDF was forced to buy electricity on the market to supply customers. The government, meanwhile, imposed a cap on electricity prices, leaving EDF selling power at a discount.

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FortisAlberta COVID-19 response delivers safe electricity distribution across Alberta, with remote monitoring, 24/7 support, outage alerts, dispersed crews, and business continuity measures to sustain essential services for customers and communities.

Key Points

Plan ensuring reliable electricity in Alberta through 24/7 support, remote monitoring, outage alerts, and dispersed crews.

✅ 24/7 customer support via 310-WIRE and mobile app

✅ Remote monitoring and rapid outage restoration

✅ Dispersed crews in 50 communities for faster response

As the COVID-19 pandemic continues to evolve in Alberta (and around the world), FortisAlberta is taking the necessary actions and precautions informed by utility disaster planning to protect the health and well-being of its employees and to provide electricity service to its customers. FortisAlberta serves more than half a million customers with the electricity they depend on to take care of their families and community members throughout our province.

"We recognize these are challenging times as while most Albertans are asked to stay home others continue to work in the community to provide essential services, including utility workers in Ontario demonstrating support efforts. As your electricity distribution provider, please be assured you can count on us to do what we do best – provide our customers with safe and reliable electricity service wherever and whenever they need it," says Michael Mosher, FortisAlberta President and CEO.

FortisAlberta is proud to be a part of the communities it serves and commits to keeping the lights on for its customers. The company is providing a full range of services for its customers and has instilled best practices within critical parts of its business. The company's control centre continues to remotely monitor, control, and restore, where possible, the delivery of power across the entire province, including during events such as an Alberta grid alert that stress the system. Early in March, FortisAlberta implemented its business continuity plan and the company remains fully accessible to customers 24/7 by phone at 310-WIRE (9473) or through its mobile app where customers can report outages online or view details of an outage. Customers can also sign up for outage alerts to their mobile phone and/or email address to let them know if an outage does occur.

FortisAlberta's power line employees are geographically dispersed across 50 different communities so they can quickly address any issues that may arise. The company has implemented work from home measures and isolation best practices, and is planning for potential on-site lockdowns where necessary to ensure no disruption to customers.

FortisAlberta will continue to remain in close communication with its stakeholders to provide updates to customers and with industry associations to share guidance specific to the electricity sector, including insights on the evolving U.S. grid response to COVID-19 from peer utilities. FortisAlberta will also continue to invest in and empower its communities by contributing to organizations that offer programs and services aligned with the greatest needs in the communities it serves.

With the Alberta Government's recent announcement to provide relief to eligible Albertans by deferring electricity and gas charges for up to 90 days, similar to some B.C. relief measures being implemented, FortisAlberta is committed to working with stakeholders and retail partners to ensure this option is available to customers quickly and efficiently, and to learn from initiatives like the Hydro One relief fund that support customers.

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National Grid power supply warning highlights electricity shortage risks amid low wind output, generator outages, and cold weather, reducing capacity margins and grid stability; considering demand response and reserve power to avoid blackout risk.

Key Points

An alert that reduced capacity from low wind and outages requires actions to maintain UK grid stability.

✅ Low wind output and generator outages reduce capacity margins

✅ ESO exploring demand response and reserve generation options

✅ Aim: maintain grid stability and avoid blackout risk

National Grid has warned that Britain’s electricity will be in short supply over the next few days after a string of unplanned power plant outages and unusually low wind speeds this week, as cheap wind power wanes across the system.

The electricity system operator said it will take action to “make sure there is enough generation” during the cold weather spell, including virtual power plants and other demand-side measures, to prevent a second major blackout in as many years.

“Unusually low wind output coinciding with a number of generator outages means the cushion of spare capacity we operate the system with has been reduced,” the company told its Twitter followers.

“We’re exploring measures and actions to make sure there is enough generation available to increase our buffer of capacity.”

A spokeswoman for National Grid said the latest electricity supply squeeze was not expected to be as severe as recorded last month, following reports that the government’s emergency energy plan was not going ahead, and added that the company did not expect to issue an official warning in the next 24 hours.

“We’re monitoring how the situation develops,” she said.

The warning is the second from the electricity system operator in recent weeks. In mid-September the company issued an official warning to the electricity market as peak power prices climbed, that its ‘buffer’ of power reserves had fallen below 500MW and it may need to call on more power plants to help prevent a blackout. The notice was later withdrawn.

Concerns over National Grid’s electricity supplies have been relatively rare in recent years. It was forced in November 2015 to ask businesses to cut their demand as a “last resort” measure to keep the lights on after a string of coal plant breakdowns.

But since then, National Grid’s greater challenge has been an oversupply of electricity, partly due to record wind generation, which has threatened to overwhelm the grid during times of low electricity demand.

National Grid has already spent almost £1bn on extra measures to prevent blackouts over the first half of the year by paying generators to produce less electricity during the coronavirus lockdown, as daily demand fell.

The company paid wind farms to turn off, and EDF Energy to halve the nuclear generation from its Sizewell B nuclear plant, to avoid overwhelming the grid when demand for electricity fell by almost a quarter from last year.

The electricity supply squeeze comes a little over a year after National Grid left large parts of England and Wales without electricity after the biggest blackout in a decade left a million homes in the dark. National Grid blamed a lightning strike for the widespread power failure.

Similar supply strains have recently caused power cuts in China, underscoring how weather and generation mix can trigger blackouts.

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