Taxpayers on the hook for AECL despite privatization

Japan Electricity Crunch exposes vulnerabilities in a liberalised power market as LNG shortages, JEPX price spikes, snow-hit solar, and weak hedging strain energy security and retail providers amid cold snap demand and limited reserve capacity.

Key Points

A winter demand shock and LNG shortfalls sent JEPX to records, exposing gaps in hedging, data, and energy security.

✅ JEPX wholesale prices spiked to an all-time high

✅ LNG inventories and procurement proved insufficient

✅ Snow disabled solar; new entrants lacked hedging

Japan's worst electricity crunch since the aftermath of the Fukushima crisis has exposed vulnerabilities in the country's recently liberalised power market, although some of the problems appear self-inflicted.

Power prices in Japan hit record highs last month, mirroring UK peak power prices during tight conditions, as a cold snap across northeast Asia prompted a scramble for supplies of liquefied natural gas (LNG), a major fuel for the country's power plants. Power companies urged customers to ration electricity to prevent blackouts, although no outages occurred.

The crisis highlighted how many providers were unprepared for such high demand. Experts say LNG stocks were not topped up ahead of winter and snow disabled solar power farms, while China's power woes strained solar supply chains.

The hundreds of small power companies that sprang up after the market was opened in 2016 have struggled the most, saying the government does not disclose the market data they need to operate. The companies do not have their own generators, instead buying electricity on the wholesale market.

Prices on the Japan Electric Power Exchange (JEPX) hit a record high of 251 yen ($2.39) per kilowatt hour in January, equating to $2,390 per megawatt hour of electricity, above record European price surges seen recently and the highest on record anywhere in the world. One megawatt hour is roughly what an average home in the U.S. would consume over 35 days.

But the vast majority of the new, smaller companies are locked into low, fixed rates they set to lure customers from bigger players, crushing them financially during a price spike like the one in January.

More than 50 small power providers wrote on Jan. 18 to Japan's industry minister, Hiroshi Kajiyama, who oversees the power sector, asking for more accessible data on supply and demand, reserve capacity and fuel inventories.

"By organising and disclosing this information, retail electricity providers will be able to bid at more appropriate prices," said the companies, led by Looop Co.

They also called on Kajiyama to require transmission and distribution companies to pass on some of the unexpected profits from price spikes to smaller operators.

The industry ministry said it had started releasing more timely market data, and is reviewing the cause of the crunch and considering changes, echoing calls by Fatih Birol to keep electricity options open amid uncertainty.

Japan reworked its power markets after the Fukushima nuclear disaster in 2011, liberalizing the sector in 2016 while pushing for more renewables.

But Japan is still heavily reliant on LNG and coal, and only four of 33 nuclear reactors are operating. The power crisis has led to growing calls to restart more reactors.

Kazuno Power, a small retail provider controlled by a municipality of the same name in northern Japan, where abundant renewable energy is locally produced, buys electricity from hydropower stations and JEPX.

During the crunch, the company had to pay nearly 10 times the usual price, Kazuno Power president Takao Takeda said in an interview. Like most other new providers, it could not pass on the costs, lost money, and folded. The local utility has taken over its customers.

"There is a contradiction in the current system," Takeda said. "We are encouraged to locally produce power for local consumption as well as use more renewable energy, but prices for these power supplies are linked to wholesale prices, which depend on the overall power supply."

The big utilities, which receive most of their LNG on long-term contracts, blamed the power shortfall on a tight spot market and glitches at generation units.

"We were not able to buy as much supply as we wanted from the spot market because of higher demand from South Korea and China, where power cuts have tightened supply," Kazuhiro Ikebe, the head of the country's electricity federation, said recently.

Ikebe is also president of Kyushu Electric Power, which supplies the southern island of Kyushu.

Utilities took extreme measures - from burning polluting fuel oil in coal plants to scavenging the dregs from empty LNG tankers - to keep the grid from breaking down.

"There is too much dependence on JEPX for procurement," said Bob Takai, the local head of European Energy Exchange, where electricity pricing reforms are being discussed, and which started offering Japan power futures last year. He added that new entrants were not hedging against sharp price moves.

Three people, who requested anonymity because of the sensitivity of the matter, were more blunt. One called the utilities arrogant in assuming they could find LNG cargoes in a pinch. Prices were already rising as China snapped up supplies, the sources noted.

"You had volatility caused by people saying 'Oh, well, demand is going to be weak because of coronavirus impacts' and then saying 'we can rely more on solar than in the past,' but solar got snowed out," said a senior executive from one generator. "We have a problem of who is charge of energy security in Japan."

Inventories of LNG, generally about two weeks worth of supplies, were also not topped up enough to prepare for winter, a market analyst said.

The fallout from the crunch has become more apparent in recent days, with new power companies like Rakuten Inc suspending new sales and Tokyo Gas, along with traditional electricity utilities, issuing profit downgrades or withdrawing their forecasts.

Although prices have fallen sharply as temperatures warmed up slightly and more generation units have come back online, the power generator executive said, "we are not out of the woods yet."
 

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New Brunswick Small Modular Reactors promise clean energy, jobs, and economic growth, say NB Power, ARC Nuclear, and Moltex Energy; critics cite cost overruns, nuclear waste risks, market viability, and reliance on government funding.

Key Points

Compact reactors proposed in NB to deliver low-carbon power and jobs; critics warn of costs, waste, and market risks.

✅ Promised jobs, exports, and net-zero support via NB Power partnerships

✅ Critics cite cost overruns, nuclear waste, and weak market demand

✅ Government funding pivotal; ARC and Moltex advance licensing

When Mike Holland talks about small modular nuclear reactors, he sees dollar signs.

When the Green Party hears about them, they see danger signs.

The loquacious Progressive Conservative minister of energy development recently quoted NB Power's eye-popping estimates of the potential economic impact of the reactors: thousands of jobs and a $1 billion boost to the provincial economy.

"New Brunswick is positioned to not only participate in this opportunity, but to be a world leader in the SMR field," Holland said in the legislature last month.

'Huge risk' nuclear deal could let Ontario push N.B. aside, says consultant
'Many issues' with modular nuclear reactors says environmental lawyer
Green MLAs David Coon and Kevin Arseneau responded cheekily by ticking off the Financial and Consumer Services Commission's checklist on how to spot a scam.

Is the sales pitch from a credible source? Is the windfall being promised by a reputable institution? Is the risk reasonable?

For small nuclear reactors, they said, the answer to all those questions is no. 

"The last thing we need to do is pour more public money down the nuclear-power drain," Coon said, reminding MLAs of the Point Lepreau refurbishment project that went $1 billion over budget.

The Greens aside, New Brunswick politicians have embraced small modular reactors as part of a broader premiers' nuclear initiative to develop SMR technology, which they say can both create jobs and help solve the climate crisis.

Smaller and cheaper, supporters say
They're "small" because, depending on the design, they would generate from three to 300 megawatts of electricity, less than, for example, Point Lepreau's 660 megawatts.

It's the modular design that is supposed to make them more affordable, as explained in next-gen nuclear guides, with components manufactured elsewhere, sometimes in existing factories, then shipped and assembled. 

Under Brian Gallant, the Liberals handed $10 million to two Saint John companies working on SMRs, ARC Nuclear and Moltex Energy.

Greens point to previous fiascoes
The Greens and other opponents of nuclear power fear SMRS are the latest in a long line of silver-bullet fiascoes, from the $23 million spent on the Bricklin in 1975 to $63.4 million in loans and loan guarantees to the Atcon Group a decade ago.

"It seems that [ARC and Moltex] have been targeting New Brunswick for another big handout ... because it's going to take billions of dollars to build these things, if they ever get off the drawing board," said Susan O'Donnell, a University of New Brunswick researcher.

O'Donnell, who studies technology adoption in communities, is part of a small new group called the Coalition for Responsible Energy Development formed this year to oppose SMRs.

"What we really need here is a reasonable discussion about the pros and cons of it," she said.

Government touts economic spinoffs
According to the Higgs government's throne speech last month, if New Brunswick companies can secure just one per cent of the Canadian market for small reactors, the province would see $190 million in revenue. 

The figures come from a study conducted for NB Power by University of Moncton economist Pierre-Marcel Desjardins.

But a four-page public summary does not include any sales projections and NB Power did not provide them to CBC News. 

"What we didn't see was a market analysis," O'Donnell said. "How viable is the market? … They're all based on a hypothetical market that probably doesn't exist."

O'Donnell said her group asked for the full report but was told it's confidential because it contains sensitive commercial information.

Holland said he's confident there will be buyers. 

"It won't be hard to find communities that will be looking for a cost effective, affordable, safe alternative to generate their electricity and do it in a way that emits zero emissions," he said.

SMRs come in different sizes and while some proponents talk about using "micro" reactors to provide electricity to remote northern First Nations communities, ARC and Moltex plan larger models to sell to power utilities looking to shift away from coal and gas.

"We have utilities and customers across Canada, where Ontario's first SMR groundbreaking has occurred already, across the United States, across Asia and Europe saying they desperately want a technology like this," said Moltex's Saint John-based CEO for North America Rory O'Sullivan. 

"The market is screaming for this product," he said, adding "all of the utilities" in Canada are interested in Moltex's reactors

ARC's CEO Norm Sawyer is more specific, guessing 30 per cent of his SMR sales will be in Atlantic Canada, 30 per cent in Ontario, where Darlington SMR plans are advancing, and 40 per cent in Alberta and Saskatchewan — all provincial power grids.

O'Donnell said it's an important question because without a large number of guaranteed sales, the high cost of manufacturing SMRs would make the initiative a money-loser. 

The cost of building the world's only functioning SMR, in Russia, was four times what was expected. 

An Australian government agency said initial cost estimates for such major projects "are often initially too low" and can "overrun." 

Up-front costs can be huge
University of British Columbia physicist M.V. Ramana, who has authored studies on the economics of nuclear power, said SMRs face the same financial reality as any large-scale manufacturing.

"You're going to spend a huge amount of money on the basic fixed costs" at the outset, he said, with costs per unit becoming more viable only after more units are built and sold. 

He estimates a company would have to build and sell more than 700 SMRs to break even, and said there are not enough buyers for that to happen. 

But Sawyer said those estimates don't take into account technological advances.

"A lot of what's being said ... is really based on old technology," he said, estimating ARC would be viable even if it sold an amount of reactors in the low double digits. 

O'Sullivan agrees.

"In fact, just the first one alone looks like it will still be economical," he said. "In reality, you probably need a few … but you're talking about one or two, maximum three [to make a profit] because you don't need these big factories."

'Paper designs' prove nothing, says expert
Ramana doesn't buy it. 

"These are all companies that have been started by somebody who's been in the nuclear industry for some years, has a bright idea, finds an angel investor who's given them a few million dollars," he said.

"They have a paper design, or a Power Point design. They have not built anything. They have not tested anything. To go from that point … to a design that can actually be constructed on the field is an enormous amount of work." 

Both CEOs acknowledge the skepticism about SMRs.

'The market is screaming for this product,' said Moltex’s Saint John-based CEO for North America, Rory O’Sullivan. (Brian Chisholm, CBC)
"I understand New Brunswick has had its share of good investments and its share of what we consider questionable investments," said Sawyer, who grew up in Rexton.

But he said ARC's SMR is based on a long-proven technology and is far past the on-paper design stage "so you reduce the risk." 

Moltex is now completing the first phase of the Canadian Nuclear Safety Commission's review of its design, a major hurdle. ARC completed that phase last year.

But, Ramana said there are problems with both designs. Moltex's molten salt model has had "huge technical challenges" elsewhere while ARC's sodium-cooled system has encountered "operational difficulties."

Ottawa says nuclear is needed for climate goals
The most compelling argument for looking at SMRs may be Ottawa's climate change goals, and international moves like the U.K.'s green industrial revolution plan point to broader momentum.  

The national climate plan requires NB Power to phase out burning coal at its Belledune generating station by 2030. It's scrambling to find a replacement source of electricity.

The Trudeau government's throne speech in October promised to "support investments in renewable energy and next-generation clean energy and technology solutions."

And federal Natural Resources Minister Seamus O'Regan told CBC earlier this year that he's "very excited" about SMRs and has called nuclear key to climate goals in Canada as well.

"We have not seen a model where we can get to net-zero emissions by 2050 without nuclear,"  he said.

O'Donnell said while nuclear power doesn't emit greenhouse gases, it's hardly a clean technology because of the spent nuclear fuel waste. 

Government support is key 
She also wonders why, if SMRs make so much sense, ARC and Moltex are relying so much on government money rather than private capital.

Holland said "the vast majority" of funding for the two companies "has to come from private sector investments, who will be very careful to make sure they get a return on that investment."

Sawyer said ARC has three dollars for every dollar it has received from the province, and General Electric has a minority ownership stake in its U.S.-based parent company.

O'Sullivan said Moltex has attracted $5 million from a European engineering firm and $6 million from "the first-ever nuclear crowdfunding campaign." 

But he said for new technologies, including nuclear power, "you need government to show policy support.

"Nuclear technology has always been developed by governments around the world. This is a very new change to have an industry come in and lead this, so private investors can't take the risk to do that on their own," he said. 

So far, Ottawa hasn't put up any funding for ARC or Moltex. During the provincial election campaign, Higgs implied federal money was imminent, but there's been no announcement in the almost three months since then.

Last month the federal government announced $20 million for Terrestrial Energy, an Ontario company working on SMRs, alongside OPG's commitment to SMRs in the province, underscoring momentum.

"We know we have the best technology pitch," O'Sullivan said. "There's others that are slightly more advanced than us, but we have the best overall proposition and we think that's going to win out at the end of the day."

But O'Donnell said her group plans to continue asking questions about SMRs. 

"I think what we really need is to have an honest conversation about what these are so that New Brunswickers can have all the facts on the table," she said.

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UK low-carbon electricity 2019 saw stalled growth as renewables rose slightly, wind expanded, nuclear output fell, coal hit record lows, and net-zero targets demand faster deployment to cut CO2 intensity below 100gCO2/kWh.

Key Points

Low-carbon sources supplied 54% of UK power in 2019, up just 1TWh; wind grew, nuclear fell, and coal dropped to 2%.

✅ Wind up 8TWh; nuclear down 9TWh amid outages

✅ Fossil fuels 43% of generation; coal at 2%

✅ Net-zero needs 15TWh per year added to 2030

The amount of electricity generated by low-carbon sources in the UK stalled in 2019, Carbon Brief analysis shows.

Low-carbon electricity output from wind, solar, nuclear, hydro and biomass rose by just 1 terawatt hour (TWh, less than 1%) in 2019. It represents the smallest annual increase in a decade, where annual growth averaged 9TWh. This growth will need to double in the 2020s to meet UK climate targets while replacing old nuclear plants as they retire.

Some 54% of UK electricity generation in 2019 came from low-carbon sources, including 37% from renewables and 20% from wind alone, underscoring wind's leading role in the power mix during key periods. A record-low 43% was from fossil fuels, with 41% from gas and just 2% from coal, also a record low. In 2010, fossil fuels generated 75% of the total.

Carbon Brief’s analysis of UK electricity generation in 2019 is based on figures from BM Reports and the Department for Business, Energy and Industrial Strategy (BEIS). See the methodology at the end for more on how the analysis was conducted.

The numbers differ from those published earlier in January by National Grid, which were for electricity supplied in Great Britain only (England, Wales and Scotland, but excluding Northern Ireland), including via imports from other countries.

Low-carbon low
In 2019, the UK became the first major economy to target net-zero greenhouse gas emissions by 2050, increasing the ambition of its legally binding Climate Change Act.

To date, the country has cut its emissions by around two-fifths since 1990, with almost all of its recent progress coming from the electricity sector.

Emissions from electricity generation have fallen rapidly in the decade since 2010 as coal power has been almost phased out and even gas output has declined. Fossil fuels have been displaced by falling demand and by renewables, such as wind, solar and biomass.

But Carbon Brief’s annual analysis of UK electricity generation shows progress stalled in 2019, with the output from low-carbon sources barely increasing compared to a year earlier.

The chart below shows low-carbon generation in each year since 2010 (grey bars) and the estimated level in 2019 (red). The pale grey bars show the estimated future output of existing low-carbon sources after old nuclear plants retire and the pale red bars show the amount of new generation needed to keep electricity sector emissions to less than 100 grammes of CO2 per kilowatt hour (gCO2/kWh), the UK’s nominal target for the sector.

 Annual electricity generation in the UK by fuel, terawatt hours, 2010-2019. Top panel: fuel by fuel. Bottom panel: cumulative total generation from all sources. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
As the chart shows, the UK will require significantly more low-carbon electricity over the next decade as part of meeting its legally binding climate goals.

The nominal 100gCO2/kWh target for 2030 was set in the context of the UK’s less ambitious goal of cutting emissions to 80% below 1990 levels by 2050. Now that the country is aiming to cut emissions to net-zero by 2050, that 100gCO2/kWh indicator is likely to be the bare minimum.

Even so, it would require a rapid step up in the pace of low-carbon expansion, compared to the increases seen over the past decade. On average, low-carbon generation has risen by 9TWh each year in the decade since 2010 – including a rise of just 1TWh in 2019.

Given scheduled nuclear retirements and rising demand expected by the Committee on Climate Change (CCC) – with some electrification of transport and heating – low-carbon generation would need to increase by 15TWh each year until 2030, just to meet the benchmark of 100gCO2/kWh.

For context, the 3.2 gigawatt (GW) Hinkley C new nuclear plant being built in Somerset will generate around 25TWh once completed around 2026. The world’s largest offshore windfarm, the 1.2GW Hornsea One scheme off the Yorkshire coast, will generate around 5TWh each year.

The new Conservative government is targeting 40GW of offshore wind by 2030, up from today’s figure of around 8GW. If policies are put in place to meet this goal, then it could keep power sector emissions below 100gCO2/kWh, depending on the actual performance of the windfarms built.

However, new onshore wind and solar, further new nuclear or other low-carbon generation, such as gas with carbon capture and storage (CCS), is likely to be needed if demand is higher than expected, or if the 100gCO2/kWh benchmark is too weak in the context of net-zero by 2050.

The CCC says it is “likely” to “reflect the need for more rapid deployment” of low-carbon towards net-zero emissions in its advice on the sixth UK carbon budget for 2033-2037, due in September.

Trading places
Looking more closely at UK electricity generation in 2019, Carbon Brief’s analysis shows why there was so little growth for low-carbon sources compared to the previous year.

There was another increase for wind power in 2019 (up 8TWh, 14%), with record wind generation as several large new windfarms were completed including the 1.2GW Hornsea One project in October and the 0.6GW Beatrice offshore windfarm in Q2 of 2019. But this was offset by a decline for nuclear (down 9TWh, 14%), due to ongoing outages for reactors at Hunterston in Scotland and Dungeness in Kent.

(Analysis of data held by trade organisation RenewableUK suggests some 0.6GW of onshore wind capacity also started operating in 2019, including the 0.2GW Dorenell scheme in Moray, Scotland.)

As a result of these movements, the UK’s windfarms overtook nuclear for the first time ever in 2019, becoming the country’s second-largest source of electricity generation, and earlier, wind and solar together surpassed nuclear in the UK as momentum built. This is shown in the figure below, with wind (green line, top panel) trading places with nuclear (purple) and gas (dark blue) down around 25% since 2010 but remaining the single-largest source.

 Annual electricity generation in the UK by fuel, terawatt hours, 2010-2019. Top panel: fuel by fuel. Bottom panel: cumulative total generation from all sources. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
The UK’s currently suspended nuclear plants are due to return to service in January and March, according to operator EDF, the French state-backed utility firm. However, as noted above, most of the UK’s nuclear fleet is set to retire during the 2020s, with only Sizewell B in Suffolk due to still be operating by 2030. Hunterston is scheduled to retire by 2023 and Dungeness by 2028.

Set against these losses, the UK has a pipeline of offshore windfarms, secured via “contracts for difference” with the government, at a series of auctions. The most recent auction, in September 2019, saw prices below £40 per megawatt hour – similar to current wholesale electricity prices.

However, the capacity contracted so far is not sufficient to meet the government’s target of 40GW by 2030, meaning further auctions – or some other policy mechanism – will be required.

Coal zero
As well as the switch between wind and nuclear, 2019 also saw coal fall below solar for the first time across a full year, echoing the 2016 moment when wind outgenerated coal across the UK, after it suffered another 60% reduction in electricity output. Just six coal plants remain in the UK, with Aberthaw B in Wales and Fiddlers Ferry in Cheshire closing in March.

Coal accounted for just 2% of UK generation in 2019, a record-low coal share since centralised electricity supplies started to operate in 1882. The fuel met 40% of UK needs as recently as 2012, but has plummeted thanks to falling demand, rising renewables, cheaper gas and higher CO2 prices.

The reduction in average coal generation hides the fact that the fuel is now often not required at all to meet the UK’s electricity needs. The chart below shows the number of days each year when coal output was zero in 2019 (red line) and the two previous years (blue).

 Cumulative number of days when UK electricity generation from renewable sources has been higher than that from fossil fuels. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
The 83 days in 2019 with zero coal generation amount to nearly a quarter of the year and include the record-breaking 18-day stretch without the fuel.

Great Britain has been running for a record TWO WEEKS without using coal to generate electricity – the first time this has happened since 1882.

The country’s grid has been coal-free for 45% of hours in 2019 so far.https://www.carbonbrief.org/countdown-to-2025-tracking-the-uk-coal-phase-out …

Coal generation was set for significant reductions around the world in 2019 – including a 20% reduction for the EU as a whole – according to analysis published by Carbon Brief in November.

Notably, overall UK electricity generation fell by another 9TWh in 2019 (3%), bringing the total decline to 58TWh since 2010. This is equivalent to more than twice the output from the Hinkley C scheme being built in Somerset. As Carbon Brief explained last year, falling demand has had a similar impact on electricity-sector CO2 emissions as the increase in output from renewables.

This is illustrated by the fact that the 9TWh reduction in overall generation translated into a 9TWh (6%) cut in fossil-fuel generation during 2019, with coal falling by 10TWh and gas rising marginally.

Increasingly renewable
As fossil-fuel output and overall generation have declined, the UK’s renewable sources of electricity have continued to increase. Their output has risen nearly five-fold in the past decade and their share of the UK total has increased from 7% in 2010 to 37% in 2019.

As a result, the UK’s increasingly renewable grid is seeing more minutes, hours and days during which the likes of wind, solar and biomass collectively outpace all fossil fuels put together, and on some days wind is the main source as well.

The chart below shows the number of days during each year when renewables generated more electricity than fossil fuels in 2019 (red line) and each of the previous four years (blue lines). In total, nearly two-fifths of days in 2019 crossed this threshold.

 Cumulative number of days when the UK has not generated any electricity from coal. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
There were also four months in 2019 when renewables generated more of the UK’s electricity than fossil fuels: March, August, September and December. The first ever such month came in September 2018 and more are certain to follow.

National Grid, which manages Great Britain’s high-voltage electricity transmission network, is aiming to be able to run the system without fossil fuels by 2025, at least for short periods. At present, it sometimes has to ask windfarm operators to switch off and gas plants to start running in order to keep the electricity grid stable.

Note that biomass accounted for 11% of UK electricity generation in 2019, nearly a third of the total from all renewables. Some two-thirds of the biomass output is from “plant biomass”, primarily wood pellets burnt at Lynemouth in Northumberland and the Drax plant in Yorkshire. The remainder was from an array of smaller sites based on landfill gas, sewage gas or anaerobic digestion.

The CCC says the UK should “move away” from large-scale biomass power plants, once existing subsidy contracts for Drax and Lynemouth expire in 2027.

Using biomass to generate electricity is not zero-carbon and in some circumstances could lead to higher emissions than from fossil fuels. Moreover, there are more valuable uses for the world’s limited supply of biomass feedstock, the CCC says, including carbon sequestration and hard-to-abate sectors with few alternatives.

Methodology
The figures in the article are from Carbon Brief analysis of data from BEIS Energy Trends chapter 5 and chapter 6, as well as from BM Reports. The figures from BM Reports are for electricity supplied to the grid in Great Britain only and are adjusted to include Northern Ireland.

In Carbon Brief’s analysis, the BM Reports numbers are also adjusted to account for electricity used by power plants on site and for generation by plants not connected to the high-voltage national grid. This includes many onshore windfarms, as well as industrial gas combined heat and power plants and those burning landfill gas, waste or sewage gas.

By design, the Carbon Brief analysis is intended to align as closely as possible to the official government figures on electricity generated in the UK, reported in BEIS Energy Trends table 5.1.

Briefly, the raw data for each fuel is in most cases adjusted with a multiplier, derived from the ratio between the reported BEIS numbers and unadjusted figures for previous quarters.

Carbon Brief’s method of analysis has been verified against published BEIS figures using “hindcasting”. This shows the estimates for total electricity generation from fossil fuels or renewables to have been within ±3% of the BEIS number in each quarter since Q4 2017. (Data before then is not sufficient to carry out the Carbon Brief analysis.)

For example, in the second quarter of 2019, a Carbon Brief hindcast estimates gas generation at 33.1TWh, whereas the published BEIS figure was 34.0TWh. Similarly, it produces an estimate of 27.4TWh for renewables, against a BEIS figure of 27.1TWh.

National Grid recently shared its own analysis for electricity in Great Britain during 2019 via its energy dashboard, which differs from Carbon Brief’s figures.

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California Electricity Rate Overhaul proposes a fixed fee and lower per-kWh rates to boost electrification, renewables, and grid reliability, while CPUC weighs impacts on conservation, low-income customers, and time-of-use pricing across the state.

Key Points

A proposal to add fixed fees and cut per-kWh prices to drive electrification, support renewables, and balance grid costs.

✅ Fixed monthly fee plus lower volumetric per-kWh charges

✅ Aims to accelerate EVs, heat pumps, and building electrification

✅ CPUC review weighs equity, conservation, and grid reliability

California is contemplating a significant overhaul to its electricity rate structure that could bring major changes to electric bills statewide, a move that has ignited debate among environmentalists and politicians alike. The proposed modifications, spearheaded by the California Energy Commission (CEC), would introduce a fixed fee on electric bills and lower the rate per kilowatt-hour (kWh) used.

Motivations for the Change

Proponents of the plan argue that it would incentivize Californians to transition to electric appliances and vehicles, a critical aspect of the state's ambitious climate goals. They reason that a lower per-unit cost would make electricity a more attractive option for applications like home heating and transportation, which are currently dominated by natural gas and gasoline. Additionally, they believe the plan would spur investment in renewable energy sources and distributed generation, ultimately leading to a cleaner electricity grid.

California has some of the most ambitious climate goals in the country, aiming to achieve carbon neutrality by 2045. The transportation sector is the state's largest source of greenhouse gas emissions, and electrification is considered a key strategy for reducing emissions. A 2021 report by the Natural Resources Defense Council (NRDC) found that electrifying all California vehicles and buildings could reduce greenhouse gas emissions by 80% compared to 2020 levels.

Concerns and Potential Impacts

Opponents of the proposal, including some consumer rights groups, express apprehensions that it would discourage conservation efforts. They argue that with a lower per-kWh cost, Californians would have less motivation to reduce their electricity consumption. Additionally, they raise concerns that the income-based fixed charges could disproportionately burden low-income households, who may struggle to afford the base charge regardless of their overall electricity consumption.

A recent study by the CEC suggests that the impact on most Californians would be negligible, even as regulators face calls for action over soaring bills from ratepayers across the state. The report predicts that the average household's electricity bill would change by less than $5 per month under the proposed system. However, some critics argue that this study may not fully account for the potential behavioral changes that could result from the new rate structure.

Similar Initiatives and National Implications

California is not the only state exploring changes to its electricity rates to promote clean energy. Hawaii and New York have also implemented similar programs to encourage consumers to use electricity during off-peak hours. These time-varying rates, also known as time-of-use rates, can help reduce strain on the electricity grid during peak demand periods.

The California proposal has garnered national attention as other states grapple with similar challenges in balancing clean energy goals with affordability concerns amid soaring electricity prices in California and beyond. The outcome of this debate could have significant implications for the broader effort to decarbonize the U.S. power sector.

The Road Ahead

The California Public Utilities Commission (CPUC) is reviewing the proposal and anticipates making a decision later this year, with a potential income-based flat-fee structure under consideration. The CPUC will likely consider the plan's potential benefits and drawbacks, including its impact on greenhouse gas emissions, electricity costs for consumers, and the overall reliability of the grid, even as some lawmakers seek to overturn income-based charges in the legislature.

The decision on California's electricity rates is merely one piece of the puzzle in the fight against climate change. However, it is a significant one, with the potential to shape the state's energy landscape for years to come, including the future of residential rooftop solar markets and investments.

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China Energy Crisis drives electricity shortages, power cuts, and blackouts as coal prices surge, carbon-neutrality rules tighten, and manufacturing hubs ration energy, disrupting supply chains and industrial output ahead of winter demand peaks.

Key Points

A power shortfall from costly coal, price caps, and emissions targets, causing blackouts and industrial rationing.

✅ Coal prices soar while electricity tariffs are capped

✅ Factories in northeast hubs face rationing and downtime

✅ Supply chains risk delays ahead of winter demand

China is struggling with a severe shortage of electricity which has left millions of homes and businesses hit by power cuts.

Blackouts are not that unusual in the country but this year a number of factors have contributed to a perfect storm for electricity suppliers, including surging electricity demand globally.

The problem is particularly serious in China's north eastern industrial hubs as winter approaches - and is something that could have implications for the rest of the world.

Why has China been hit by power shortages?
The country has in the past struggled to balance electricity supplies with demand, which has often left many of China's provinces at risk of power outages.

During times of peak power consumption in the summer and winter the problem becomes particularly acute.

But this year a number of factors have come together to make the issue especially serious.

As the world starts to reopen after the pandemic, demand for Chinese goods is surging and the factories making them need a lot more power, highlighting China's electricity appetite in recent months.

Rules imposed by Beijing as it attempts to make the country carbon neutral by 2060 have seen coal production slow, even as the country still relies on coal for more than half of its power and as low-emissions generation is set to cover most global demand growth.

And as electricity demand has risen, the price of coal has been pushed up.

But with the government strictly controlling electricity prices, coal-fired power plants are unwilling to operate at a loss, with many drastically reducing their output instead.

Who is being affected by the blackouts?
Homes and businesses have been affected by power cuts as electricity has been rationed in several provinces and regions.

A coal-burning power plant can be seen behind a factory in China"s Inner Mongolia Autonomous Region

The state-run Global Times newspaper said there had been outages in four provinces - Guangdong in the south and Heilongjiang, Jilin and Liaoning in the north east. There are also reports of power cuts in other parts of the country.

Companies in major manufacturing areas have been called on to reduce energy usage during periods of peak demand or limit the number of days that they operate.

Energy-intensive industries such as steel-making, aluminium smelting, cement manufacturing and fertiliser production are among the businesses hardest hit by the outages.

What has the impact been on China's economy?
Official figures have shown that in September 2021, Chinese factory activity shrunk to the lowest it had been since February 2020, when power demand dropped as coronavirus lockdowns crippled the economy.

Concerns over the power cuts have contributed to global investment banks cutting their forecasts for the country's economic growth.

Goldman Sachs has estimated that as much as 44% of the country's industrial activity has been affected by power shortages. It now expects the world's second largest economy to expand by 7.8% this year, down from its previous prediction of 8.2%.

Globally, the outages could affect supply chains, including solar supply chains as the end-of-the-year shopping season approaches.

Since economies have reopened, retailers around the world have already been facing widespread disruption amid a surge in demand for imports.

China's economic planner, the National Development and Reform Commission (NDRC), has outlined a number of measures to resolve the problem, with energy supplies in the northeast of the country as its main priority this winter.

The measures include working closely with generating firms to increase output, ensuring full supplies of coal and promoting the rationing of electricity.

The China Electricity Council, which represents generating firms, has also said that coal-fired power companies were now "expanding their procurement channels at any cost" in order to guarantee winter heat and electricity supplies.

However, finding new sources of coal imports may not be straightforward.

Russia is already focused on its customers in Europe, Indonesian output has been hit by heavy rains and nearby Mongolia is facing a shortage of road haulage capacity,

Are energy shortages around the world connected?
Power cuts in China, UK petrol stations running out of fuel, energy bills jumping in Europe, near-blackouts in Japan and soaring crude oil, natural gas and coal prices on wholesale markets - it would be tempting to assume the world is suddenly in the grip of a global energy drought.

However, it is not quite as simple as that - there are some distinctly different issues around the world.

For example, in the UK petrol stations have run dry as motorists rushed to fill up their vehicles over concerns that a shortage of tanker drivers would mean fuel would soon become scarce.

Meanwhile, mainland Europe's rising energy bills and record electricity prices are due to a number of local factors, including low stockpiles of natural gas, weak output from the region's windmills and solar farms and maintenance work that has put generating operations out of action.
 

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COVID-19 Impact on US Electric Grid: utilities, ERCOT, PJM, and MISO brace for load shifts as remote work rises, industrial demand falls, and nuclear plants enforce pandemic planning to maintain reliability and resilience.

Key Points

Pandemic-driven changes in electricity demand and operations as utilities shift to remote work and reduced industrial use.

✅ Utilities enact remote work and suspend disconnections

✅ Grid operators model load shifts and maintain reliability

✅ Nuclear plants sustain operations with pandemic protocols

Operators of the nation's electric grid and energy companies are bracing for the spread of a virus that is undercutting power demand in countries across Asia and Europe as daily activities grind to a halt.

Owners of U.S. utilities and nuclear plants are canceling events, halting travel, pushing remote work and testing ill workers to slow the spread of the novel coronavirus.

So far, grid operators in the United States say no substantial effect on the electricity demand has emerged, but that could change, even though some reports indicate the U.S. grid is safe for now amid COVID-19. Texas' main grid operator, the Electric Reliability Council of Texas (ERCOT), expressed uncertainty when asked whether it will see changes in demand patterns for power due to the virus.

"It's too early to tell," Leslie Sopko, a spokeswoman for ERCOT, said in an email.

The virus has already taken a toll on power demand overseas. The chairman of Japan's federation of electric utilities and president of Chubu Electric Power Co., Satoru Katsuno, told reporters Friday the country's power demand has weakened as industrial activity slows due to the outbreak, according to Reuters.

The news outlet similarly reported China's industrial power demand this year may decline as the virus curtailed factory output and prevented some employees from returning to work. And, according to Bloomberg, power use in Italy slumped 7.4% last week after the government there shut down schools and told workers to remain home, while Ontario electricity demand also declined as people stayed home.

U.S. utility executives said the sector is well prepared and has faced the threat of spreading infections before. More than a decade ago, global virus scares like SARS pushed companies to hammer out extensive disaster planning, and those have stuck.

"A lot of the foundational work on contingency planning is actually rooted in pandemic planning because of those experiences in the mid-2000s," Scott Aaronson, the Edison Electric Institute's vice president of security and preparedness, told E&E News. "There is a good body of work and a lot of planning and exercises that have gone into being able to operate through these challenges."

Keeping the nation's electric grid running is a top priority at the Department of Energy, said Chris Fall, the agency's point person for COVID-19, which the new coronavirus causes. "Our responsibility is to make sure the electrical grid is resilient and working," said Fall, who directs the department's Office of Science.

He told an agency podcast, called "Direct Current," that the department is working with the private sector and other elements of the energy system. "Obviously we are connected with other agencies like Homeland Security or [the Federal Energy Regulatory Commission] on things like the electrical grid and making sure we have power, and if those people get sick or impacted, we have backups for all of that," he said.

According to a bulletin EEI released on the issue, 40% of a company's employees could be out sick, be quarantined or stay home to care for sick family members. And pandemics may prevent "traditional mutual assistance programs that help companies restore service after natural disasters and weather events," EEI said, such as restoring power in Florida after major storms.

The utility sector is also juggling the needs of its customers. Many major utilities across the nation have vowed to suspend shut-offs and keep power, heat and water on for all customers — a particular concern for people who may be out of work and cannot afford to pay their bills. Companies are also suspending disconnections for nonpayment, some under direction from officials and regulators in states like Ohio and Connecticut, while in Canada Hydro One's peak rate policy has drawn attention among self-isolating customers.

Like other businesses preparing for pandemics, utilities focus on keeping the workforce healthy and operations running. But EEI's Aaronson noted that a key difference with keeping critical infrastructure humming is the possible requirement for the sheltering in place of essential employees who are unable to do their jobs from home, as some operators contemplate locking down key staff at work sites to ensure continuity.

Grid operators are also well-equipped to handle shifts in power demand, and he acknowledged the sector could see changes as more offices and businesses move to remote working. He compared it to the load demand shifts between weekdays and weekends.

"So on the weekends, you're going to have a lot of people at home," Aaronson said. "During the week, it's people in offices. But generally speaking, the ability to have that resiliency and redundancy, the ability to shift resources and the way the grid balances, that is not going to change."

Electricity demand from high-intensity industries like manufacturing or theme parks like Disneyland could also wane, he added, even as electricity inequality in California influences who is most affected.

"It's not just a load shift to the residential, but it's also the load drop in some cases," Aaronson said. "Some of the commercial and industrial customers are going to be working a little bit less than they are presently."

Nuclear plants
Work is continuing at the Plant Vogtle nuclear construction project after Georgia Power Co. announced that one of the site workers is being tested for the coronavirus. The utility does not have the results of that test, a Georgia Power spokesman said late yesterday afternoon. The person works primarily in an office setting and is not on the construction site where two nuclear reactors are being built.

A second worker was tested Saturday, and those results were negative, spokesman John Kraft told E&E News.

Vogtle boasts a high worker count of 9,000 across the entire construction site, which includes office buildings. This is mostly craft laborers, but there are also administrators, executives and Nuclear Regulatory Commission safety inspectors.

A number of contractors and vendors are also on site given the complexity of the project.

Employees who were near the office worker being tested have been sent home until the company receives results. If the test is positive, then those workers will stay home for 14 days, Georgia Power said.

"The company is taking every action to prepare for impacts of the COVID-19 pandemic," Kraft said in a statement. This includes using advice from medical professionals and the Atlanta-based Centers for Disease Control and Prevention.

Georgia Power, owned by Atlanta-based Southern Co., informed regulators at the NRC that a worker was being tested. The federal commission itself has pandemic plans in place to ensure continued oversight, including robust work-from-home capabilities and "social distancing" practices to limit close contact among employees at headquarters.

NRC spokesman Scott Burnell said in an email that telework is not unusual for the agency, and about 75% of its workforce is already equipped to work remotely. The commission tested its telework readiness Friday. Some positions require workers to stay on-site to ensure safe reactor operations, Burnell added.

The nuclear industry has maintained pandemic preparedness plans and procedures since 2006, which have been shared with federal agencies, according to Mary Love, a spokeswoman for the Nuclear Energy Institute. "NEI members are participating in weekly calls to facilitate communications, coordination and best practices," she said.

According to NEI statistics, each plant averages 500 to 1,000 workers. While not every position is essential to operations, some areas like the control room cannot be conducted remotely.

"We know that nuclear power plant operations and the availability of electric service will be tremendously important in minimizing the impact of the situation on the general public," Love added. "We are confident, based on extensive planning, that the industry will continue to operate nuclear plants safely as this event unfolds."

Grid operators
Hundreds of workers responsible for overseeing critical operations of the U.S. electric grid are being encouraged to work from home, their offices are being sanitized, and in-person meetings are being moved online.

PJM Interconnection, the nation's largest grid operator covering some 65 million people across Mid-Atlantic and Midwest states, said Friday a forecast on load changes was not yet available.

PJM has moved all stakeholder meetings online. Employee travel has been suspended, as have external visits to its headquarters in Valley Forge, Pa.

Employees "are equipped to work remotely, if necessary, to maintain business continuity," and PJM "is prepared and able to run and support all market applications from its campus or remotely, as needed," the operator said.

"PJM recognizes that these measures have significant impacts to our staff, members and stakeholders," PJM said on its coronavirus response webpage. "We are dedicated to striking a balance between those impacts and our number one priority — the reliability of the grid."

Still pending at the operator is a decision about its annual meeting in Chicago at the beginning of May. That decision will be made by April 3, PJM said.

The Midcontinent Independent System Operator (MISO), which runs the bulk power grid across 15 states and the Canadian province of Manitoba, is also holding meetings via conference call or online and restricting all business travel.

MISO has encouraged "nonessential" employees to work remotely, leaving only those who actively monitor and manage the operation of the grid working on-site.

The grid operator employs nearly 1,000 people, including 780 at its headquarters in Carmel, Ind.

A board meeting set for the last week of March in New Orleans hasn't yet been canceled, with a final decision on whether to move forward with the meeting expected today.

MISO said it hasn't encountered other changes in normal operations and has not seen significant shifts in electricity demand.

In Texas, ERCOT has about 750 employees, mostly at its campus in the city of Taylor. ERCOT's Sopko said the grid operator is encouraging employees who are not required to be on-site to work from home. The policy is voluntary at this time, but that could change quickly, she said Friday.

ERCOT is also taking extra steps to keep workers safe, including alternating use of facilities, encouraging social distancing and imposing control room measures as part of its pandemic planning, she added.

Energy companies
In the Midwest, utilities including DTE Energy Co., Commonwealth Edison, Consumers Energy and Ameren Corp. said they're following CDC guidance and working with state and local officials to help slow the spread of the virus. That means asking employees who can do their jobs at home to do so, restricting visitors to company offices, canceling large assemblies and nonessential business travel, and holding meetings by phone or online.

Chicago-based ComEd, which serves 4 million customers, is imposing a moratorium on service disconnections and waiving new late payment charges through at least May 1, in addition to working with customers who are facing financial hardships on a case-by-case basis to establish payment arrangements and identify energy assistance options, spokesman Paul Elsberg said.

Many of the Southeast's major energy companies are also curbing travel and encouraging telework, among other steps, in response to the coronavirus.

For Southern Co., this includes its Georgia Power unit; Southern Power; and employees of Southern Company Gas, who are in Illinois, Tennessee and Virginia. Southern has not extended the policies to its Alabama and Mississippi electric companies, spokesman Schuyler Baehman said.

Charlotte, N.C.-based Duke Energy Corp. has suspended all business travel unless workers are traveling by car. The energy giant also is encouraging its employees to rethink their own vacations if upcoming trips take them out of the country.

"Circumstances are changing rapidly around the world," the company said in a statement.

For workers who must come to the office, or work at power plants or on the lines, utilities are doubling down on disinfectant in those areas.

"We're also reminding our employees that we provide a very critical service; we need you well, we need you able," said Le-Ha Anderson, a spokeswoman for Richmond, Va.-based Dominion Energy Inc.

Dominion started asking employees a few weeks ago to take mobile devices home and make sure they have what they need to work remotely. Anyone who has traveled to one of the CDC-identified hot spots is asked to stay home for 14 days with no questions asked, Anderson said.

The federally owned Tennessee Valley Authority has reviewed and updated its plans on how it will operate during a pandemic but has not yet reached the point to have employees telework if they are able to do so.

"We come at this at a very phased approach," TVA spokesman Jim Hopson said. "We can't just shut the doors."

State utility commissions, too, have begun taking steps. In response to a state of emergency declared by Ohio Gov. Mike DeWine (R), the Public Utilities Commission of Ohio on Thursday directed utilities to act where possible to avoid suspending service to customers.

Will Seuffert, executive secretary of the Minnesota Public Utilities Commission, said in an email that the regulator has canceled all public hearings and agenda meetings for the next two weeks and has been supporting telework "throughout the agency" in response to the virus.

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