FPL to build solar thermal plant in California

Ontario SMR BWRX-300 leads Canada in next-gen nuclear energy at Darlington, with GE Vernova and Hitachi, delivering clean, reliable power via modular design, passive safety, scalability, and lower costs for grid integration.

Key Points

Ontario SMR BWRX-300 is a 300 MW modular boiling water reactor at Darlington with passive safety and clean power.

✅ 300 MW BWR supplies power for about 300,000 homes

✅ Passive safety enables safe shutdown without external power

✅ Modular design reduces costs and speeds grid integration

Ontario has initiated the construction of Canada's first small modular nuclear reactor (SMR), supported by OPG's SMR commitment to deployment, marking a significant milestone in the province's energy strategy. This development positions Ontario at the forefront of next-generation nuclear technology within the G7 nations.

The project, known as the Darlington New Nuclear Project, is being led by Ontario Power Generation (OPG) in collaboration with GE Vernova and Hitachi Nuclear Energy, and through its OPG-TVA partnership on new nuclear technology development. The chosen design is the BWRX-300, a 300-megawatt boiling water reactor that is approximately one-tenth the size and complexity of traditional nuclear reactors. The first unit is expected to be operational by 2029, with plans for additional units to follow.

Each BWRX-300 reactor is projected to supply electricity to about 300,000 homes, contributing to Ontario's efforts, which include the decision to refurbish Pickering B for additional baseload capacity, to meet the anticipated 75% increase in electricity demand by 2050. The compact design of the SMR allows for easier integration into existing infrastructure, reducing the need for extensive new transmission lines.

The economic impact of the project is substantial. The construction of four such reactors is expected to create up to 18,000 jobs and contribute approximately $38.5 billion CAD to the Canadian economy, reflecting the economic benefits of nuclear projects over 65 years. The modular nature of SMRs also allows for scalability, with each additional unit potentially reducing costs through economies of scale.

Safety is a paramount consideration in the design of the BWRX-300. The reactor employs passive safety features, meaning it can safely shut down without the need for external power or operator intervention. This design enhances the reactor's resilience to potential emergencies, aligning with stringent regulatory standards.

Ontario's commitment to nuclear energy is further demonstrated by its plans for four SMRs at the Darlington site. This initiative reflects a broader strategy to diversify the province's energy mix, incorporating clean and reliable power sources to complement renewable energy efforts.

While the development of SMRs in Ontario is a significant step forward, it also aligns with the Canadian nuclear initiative positioning Canada as a leader in the global nuclear energy landscape. The successful implementation of the BWRX-300 could serve as a model for other nations exploring advanced nuclear technologies.

Ontario's groundbreaking work on small modular nuclear reactors represents a forward-thinking approach to energy generation. By embracing innovative technologies, the province is not only addressing future energy demands but also, through the Pickering NGS life extension, contributing to the global transition towards sustainable and secure energy solutions.

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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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Idaho Power Valmy Settlement outlines early closure of the North Valmy coal-fired plant in Nevada, accelerated depreciation recovery, a 1.17% base-rate increase, and impacts for customers, NV Energy co-ownership, and Idaho Public Utilities Commission review.

Key Points

A proposed agreement to close North Valmy early, recover costs via a 1.17% rate hike, and seek PUC approval.

✅ Unit 1 closes 2019; Unit 2 closes 2025 in Nevada.

✅ 1.17% base-rate hike; about $1.20 per 1,000 kWh monthly bill.

✅ Idaho PUC comment deadline May 25; NV Energy co-owner.

State regulators have set a May 25 deadline for public comment on a proposed settlement related to the early closure of a coal-fired plant co-owned by Idaho Power, even as some utilities plan to keep a U.S. coal plant running indefinitely in other jurisdictions.

The settlement calls for shuttering Unit 1 of the North Valmy Power Plant in Nevada in 2019, with Unit 2 closing in 2025, amid regional coal unit retirements debates. The units had been slated for closure in 2031 and 2035, respectively.

If approved by the Idaho Public Utilities Commission, the settlement would increase base rates by approximately $13.3 million, or 1.17 percent, in order to allow the company to recover its investment in the plant on an accelerated basis.

That equates to an additional $1.20 on the monthly bill of the typical residential customer using 1,000 kilowatt-hours of energy per month.

Idaho Power, which co-owns the plant with NV Energy, maintains that closing Valmy early rather than continuing to operate it until it is fully depreciated in 2035, will ultimately save customers $103 million in today's dollars.

The company said a significant decrease in market prices for electricity has made it uneconomic to operate the plant except during extremely cold or hot weather, when the demand for energy peaks, a trend underscored by transactions involving the San Juan Generating Station deal elsewhere. The company also said plant balances have increased by approximately $70 million since its last general rate case in 2011, due to routine maintenance and repairs, as well as investments required to meet environmental regulations.

The proposed settlement reflects a number of changes to Idaho Power's original proposal regarding Valmy, and comes in the wake of discussions with interested parties in February and April, against the backdrop of a broader energy debate over plant closures and reliability.

In its initial application, filed in October, Idaho Power proposed closing both units in 2025. The original proposal would have increased base rates by $28.5 million, or about 2.5 percent, in order to allow the company to recover its costs associated with the plant's accelerated depreciation, decommissioning and anticipated investments, with cautionary examples such as the Kemper power plant costs illustrating potential risks.

Concurrently, Idaho Power asked for commission approval to adjust depreciation rates for its other plants and equipment based on the result of a study it conducts every five years, as outlined in Case IPC-E-16-23. The adjustment would have led to a $6.7 million increase to base rates.

The two requests filed in October would have increased customer costs by a total of $35.2 million or 3.1 percent, leading to a $3.08 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

The proposed settlement submitted to the Commission on May 4 calls for $13,285,285 to be recovered from all customer classes through base rates until 2028, all related to the Valmy shutdown. That is an increase of 1.17 percent and would result in a $1.20 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

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Assault on Kyiv's Power Grid intensifies as missiles and drones strike critical energy infrastructure. Ukraine's air defenses intercept threats, yet blackouts, heating risks, and civilian systems damage mount amid escalating winter conditions.

Key Points

Missile and drone strikes on Kyiv's power grid to cripple infrastructure, cause blackouts, and pressure civilians.

✅ Targets power plants, substations, and transmission lines

✅ Air defenses intercept many missiles and drones

✅ Blackouts jeopardize heating, safety, and communications

In a troubling escalation of hostilities, Russian forces launched a relentless five-hour assault on Kyiv, employing missiles and drones to target critical infrastructure, particularly Ukraine's power grid. This attack not only highlights the ongoing conflict between Russia and Ukraine but also underscores the vulnerability of essential services, as seen in power outages in western Ukraine in recent weeks, in the face of military aggression.

The Nature of the Attack

The assault began early in the morning and continued for several hours, with air raid sirens ringing out across the capital as residents were urged to seek shelter. Eyewitnesses reported a barrage of missile strikes, along with the ominous whir of drones overhead. The Ukrainian military responded with its air defense systems, successfully intercepting a number of the incoming threats, but several strikes still managed to penetrate the defenses.

One of the most alarming aspects of this attack was its focus on Ukraine's energy infrastructure. Critical power facilities were hit, resulting in significant disruptions to electricity supply across Kyiv and surrounding regions. The attacks not only caused immediate outages but also threatened to complicate efforts to keep the lights on in the aftermath.

Impacts on Civilians and Infrastructure

The consequences of the missile and drone strikes were felt immediately by residents. Many found themselves without power, leading to disruptions in heating, lighting, and communications. With winter approaching, the implications of such outages become even more serious, as keeping the lights on this winter becomes harder while temperatures drop and the demand for heating increases.

Emergency services were quickly mobilized to assess the damage and begin repairs, but the scale of the attack posed significant challenges. In addition to the direct damage to power facilities, the strikes created a climate of fear and uncertainty among civilians, even as many explore new energy solutions to endure blackouts.

Strategic Objectives Behind the Assault

Military analysts suggest that targeting Ukraine's energy infrastructure is a calculated strategy by Russian forces. By crippling the power grid, the intention may be to sow chaos and undermine public morale, forcing the government to divert resources to emergency responses rather than frontline defenses. This tactic has been employed previously, with significant ramifications for civilian life and national stability.

Moreover, as winter approaches, the vulnerability of Ukraine’s energy systems becomes even more pronounced, with analysts warning that winter looms over the battlefront for civilians and troops alike. With many civilians relying on electric heating and other essential services, an attack on the power grid can have devastating effects on public health and safety. The psychological impact of such assaults can also contribute to a sense of hopelessness among the population, potentially influencing public sentiment regarding the war.

International Response and Solidarity

The international community has responded with concern to the recent escalation in attacks. Ukrainian officials have called for increased military support and defensive measures to protect critical infrastructure from future assaults, amid policy shifts such as the U.S. ending support for grid restoration that complicate planning. Many countries have expressed solidarity with Ukraine, reiterating their commitment to support the nation as it navigates the complexities of this ongoing conflict.

In addition to military assistance, humanitarian aid is also critical, and instances of solidarity such as Ukraine helping Spain amid blackouts demonstrate shared resilience. As the situation continues to evolve, many organizations are working to provide relief to those affected by the attacks, offering resources such as food, shelter, and medical assistance. The focus remains not only on immediate recovery efforts but also on long-term strategies to bolster Ukraine’s resilience against future attacks.

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Quebec EV transition plan aims for 2 million electric vehicles by 2030 and bans new gas cars by 2035, stressing charging infrastructure, incentives, emissions cuts, and industry impacts, with debate over feasibility and economic risks.

Key Points

A provincial policy targeting 2M EVs by 2030 and a 2035 gas-car sales ban, backed by charging buildout and incentives.

✅ Requires major charging infrastructure and grid upgrades

✅ Balances incentives with economic impacts and industry readiness

✅ Gas stations persist while EV adoption accelerates cautiously

Quebec's ambitious push to dominate the electric vehicle (EV) market, echoing Canada's EV goals in its plan, by setting a target of two million EVs on the road by 2030 and planning to ban the sale of new gas-powered vehicles by 2035 has sparked significant debate among industry experts. While the government's objectives aim to reduce greenhouse gas emissions and promote sustainable transportation, some experts question the feasibility and potential economic impacts of such rapid transitions.

Current Landscape of Gas Stations in Quebec

Contrary to Environment Minister Benoit Charette's assertion that gas stations may become scarce within the next decade, industry experts suggest that the number of gas stations in Quebec is unlikely to decline drastically. Carol Montreuil, Vice President of the Canadian Fuels Association, describes the minister's statement as "wishful thinking," emphasizing that the number of gas stations has remained relatively stable over the past decade. Statistics indicate that in 2023, Quebec residents purchased more gasoline than ever before, and EV shortages and wait times further underscore the continued demand for traditional fuel sources.

Challenges in Accelerating EV Adoption

The government's goal of having two million EVs on Quebec roads by 2030 presents several challenges. Currently, there are approximately 200,000 fully electric cars in the province. Achieving a tenfold increase in less than a decade requires substantial investments in charging infrastructure, consumer incentives, and public education to address concerns such as range anxiety and charging accessibility, especially amid electricity shortage warnings across Quebec and other provinces.

Economic Considerations and Industry Concerns

Industry stakeholders express concerns about the economic implications of rapidly phasing out gas-powered vehicles. Montreuil warns that the industry is already struggling and that attempting to transition too quickly could lead to economic challenges, a view echoed by critics who label the 2035 EV mandate delusional. He suggests that the government may be spending excessive public funds on subsidies for technologies that are still expensive and not yet widely adopted.

Public Sentiment and Adoption Rates

Public sentiment towards EVs is mixed, and experiences in Manitoba suggest the road to targets is not smooth. While some consumers, like Montreal resident Alex Rajabi, have made the switch to electric vehicles and are satisfied with their decision, others remain hesitant due to concerns about vehicle cost, charging infrastructure, and the availability of incentives. Rajabi, who transitioned to an EV nine months ago, notes that while he did not take advantage of the incentive program, he is happy with his decision and suggests that adding charging ports at gas stations could facilitate the transition.

The Need for a Balanced Approach

Experts advocate for a balanced approach that considers the pace of technological advancements, consumer readiness, and economic impacts. While the transition to electric vehicles is essential for environmental sustainability, it is crucial to ensure that the infrastructure, market conditions, and public acceptance are adequately addressed, and to recognize that a share of Canada's electricity still comes from fossil fuels, to make the shift both feasible and beneficial for all stakeholders.

In summary, Quebec's ambitious EV targets reflect a strong commitment to environmental sustainability. However, industry experts caution that achieving these goals requires careful planning, substantial investment, and a realistic assessment of the challenges involved as federal EV sales regulations take shape, in transitioning from traditional vehicles to electric mobility.

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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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