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Celtic Interconnector, a subsea electricity link between Ireland and France, connects EU grids via a high-voltage submarine cable, boosting security of supply, renewable integration, and cross-border trade with 700 MW capacity by 2026.

Key Points

A 700 MW subsea link between Ireland and France, boosting security, enabling trade, and supporting renewables.

✅ Approx. 600 km subsea cable from East Cork to Brittany

✅ 700 MW capacity; powers about 450,000 homes

✅ Financed by EIB, banks, CEF; Siemens Energy and Nexans

France and Ireland signed contracts on Friday to advance the Celtic Interconnector, a subsea electricity link to allow the exchange of electricity between the two EU countries. It will be the first interconnector between continental Europe and Ireland, as similar UK interconnector plans move forward in parallel. 

Representatives for Ireland’s electricity grid operator EirGrid and France’s grid operator RTE signed financial and technical agreements for the high-voltage submarine cable, mirroring developments like Maine’s approved transmission line in North America for cross-border power. The countries’ respective energy ministers witnessed the signing.

European commissioner for energy Kadri Simson said:

In the current energy market situation, marked by electricity price volatility, and the need to move away from imports of Russian fossil fuels, European energy infrastructure has become more important than ever.

The Celtic Interconnector is of paramount importance as it will end Ireland’s isolation from the Union’s power system, with parallels to Cyprus joining the electricity highway in the region, and ensure a reliable high-capacity link improving the security of electricity supply and supporting the development of renewables in both Ireland and France.

EirGrid and RTE signed €800 million ($827 million) worth of financing agreements with Barclays, BNP Paribas, Danske Bank, and the European Investment Bank, similar to the Lake Erie Connector investment that blends public and private capital.

In 2019, the project was awarded a Connecting Europe Facility (CEF) grant worth €530.7 million to support construction works and align with a broader push for electrification in Europe under climate strategies. The CEF program also provided €8.3 million for the Celtic Interconnector’s feasibility study and initial design and pre-consultation.

Siemens Energy will build converter stations in both countries, and Paris-based global cable company Nexans will design and install a 575-km-long cable for the project.

The cable will run between East Cork, on Ireland’s southern coast, and northwestern France’s Brittany coast and will connect into substations at Knockraha in Ireland and La Martyre in France.

The Celtic Interconnector, which is expected to be operational by 2026, will be approximately 600 km (373 miles) long and have a capacity of 700 MW, similar to cross-border initiatives such as Quebec-to-New York power exports expected in 2025, which is enough to power 450,000 households.

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California Rolling Blackouts expose grid reliability risks amid a heatwave, as CAISO curtails power while solar output fades at sunset, wind stalls, and scarce natural gas and nuclear capacity plus PG&E issues strain imports.

Key Points

Grid outages during heatwaves from low reserves, fading solar, weak wind, and limited firm capacity.

✅ Heatwave demand rose as solar output dropped at sunset

✅ Limited imports and gas, nuclear shortfalls cut reserves

✅ Policy, pricing, and maintenance gaps increased outage risk

Millions of Californians were denied electrical power and thus air conditioning during a heatwave, raising the risk of heatstroke and death, particularly among the elderly and sick. 

The blackouts come at a time when people, particularly the elderly, are forced to remain indoors due to Covid-19, and as later heat waves would test the grid again statewide.

At first, the state’s electrical grid operator last night asked customers to voluntarily reduce electricity use. But after lapses in power supply pushed reserves to dangerous levels it declared a “Stage 3 emergency” cutting off power to people across the state at 6:30 pm.

The immediate reason for the black-outs was the failure of a 500-megawatt power plant and an out-of-service 750-megawatt unit not being available. “There is nothing nefarious going on here,” said a spokeswoman for California Independent System Operator (CAISO). “We are just trying to run the grid.”

But the underlying reasons that California is experiencing rolling black-outs for the second time in less than a year stem from the state’s climate policies, which California policymakers have justified as necessary to prevent deaths from heatwaves, and which it is increasingly exporting to Western states as a model.

In October, Pacific Gas and Electric cut off power to homes across California to avoid starting forest fires after reports that its power lines may have started fires in recent seasons. The utility and California’s leaders had over the previous decade diverted billions meant for grid maintenance to renewables. 

And yesterday, California had to impose rolling blackouts because it had failed to maintain sufficient reliable power from natural gas and nuclear plants, or pay in advance for enough guaranteed electricity imports from other states.

It may be that California’s utilities and their regulator, the California Public Utilities Commission, which is also controlled by Gov. Newsom, didn’t want to spend the extra money to guarantee the additional electricity out of fears of raising California’s electricity prices even more than they had already raised them.

California saw its electricity prices rise six times more than the rest of the United States from 2011 to 2019, helping explain why electricity prices are soaring across the state, due to its huge expansion of renewables. Republicans in the U.S. Congress point to that massive increase to challenge justifications by Democrats to spend $2 trillion on renewables in the name of climate change.

Even though the cost of solar panels declined dramatically between 2011 and 2019, their unreliable and weather-dependent nature meant that they imposed large new costs in the form of storage and transmission to keep electricity as reliable. California’s solar panels and farms were all turning off as the blackouts began, with no help available from the states to the East already in nightfall.

Electricity from solar goes away at the very moment when the demand for electricity rises. “The peak demand was steady in late hours,” said the spokesperson for CAISO, which is controlled by Gov. Gavin Newsom, “and we had thousands of megawatts of solar reducing their output as the sunset.”

The two blackouts in less than a year are strong evidence that the tens of billions that Californians have spent on renewables come with high human, economic, and environmental costs.

Last December, a report by done for PG&E concluded that the utility’s customers could see blackouts double over the next 15 years and quadruple over the next 30.

California’s anti-nuclear policies also contributed to the blackouts. In 2013, Gov. Jerry Brown forced a nuclear power plant, San Onofre, in southern California to close.

Had San Onofre still been operating, there almost certainly would not have been blackouts on Friday as the reserve margin would have been significantly larger. The capacity of San Onofre was double that of the lost generation capacity that triggered the blackout.

California's current and former large nuclear plants are located on the coast, which allows for their electricity to travel shorter distances, and through less-constrained transmission lines than the state’s industrial solar farms, to get to the coastal cities where electricity is in highest demand.

There has been very little electricity from wind during the summer heatwave in California and the broader western U.S., further driving up demand. In fact, the same weather pattern, a stable high-pressure bubble, is the cause of heatwaves, since it brought very low wind for days on end along with very high temperatures.

Things won’t be any better, and may be worse, in the winter, with a looming shortage as it produces far less solar electricity than the summer. Solar plus storage, an expensive attempt to fix problems like what led to this blackout, cannot help through long winters of low output.

California’s electricity prices will continue to rise if it continues to add more renewables to its grid, and goes forward with plans to shut down its last nuclear plant, Diablo Canyon, in 2025.

Had California spent an estimated $100 billion on nuclear instead of on wind and solar, it would have had enough energy to replace all fossil fuels in its in-state electricity mix.

To manage the increasingly unreliable grid, California will either need to keep its nuclear plant operating, build more natural gas plants, underscoring its reliance on fossil fuels for reliability, or pay ever more money annually to reserve emergency electricity supplies from its neighbors.

After the blackouts last October, Gov. Newsom attacked PG&E Corp. for “greed and mismanagement” and named a top aide, Ana Matosantos, to be his “energy czar.” 

“This is not the new normal, and this does not take 10 years to solve,” Newsom said. “The entire system needs to be reimagined.”

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Futaba Partial Reopening marks limited access to the Fukushima exclusion zone, highlighting radiation decontamination progress, the train station restart, and regional recovery ahead of the Tokyo Olympics after the 2011 nuclear disaster and evacuation.

Key Points

A lift of entry bans in Futaba, signaling Fukushima recovery, decontamination progress, and a train station restart.

✅ Unrestricted access to 2.4 km² around Futaba Station

✅ Symbolic step ahead of Tokyo Olympics torch relay

✅ Decommissioning and decontamination to span decades

Japan's government on Wednesday opened part of the last town that had been off-limits due to radiation since the Fukushima nuclear disaster nine years ago, in a symbolic move to show the region's recovery ahead of the Tokyo Olympics, even as grid blackout risks have drawn scrutiny nationwide.

The entire population of 7,000 was forced to evacuate Futaba after three reactors melted down due to damage at the town's nuclear plant caused by a magnitude 9. 0 quake and tsunami March 11, 2011.

The partial lifting of the entry ban comes weeks before the Olympic torch starts from another town in Fukushima, as new energy projects like a large hydrogen system move forward in the prefecture. The torch could also arrive in Futaba, about 4 kilometres (2.4 miles) from the wrecked nuclear plant.

Unrestricted access, however, is only being allowed to a 2.4 square-kilometre (less than 1 square-mile) area near the main Futaba train station, which will reopen later this month to reconnect it with the rest of the region for the first time since the accident. The vast majority of Futaba is restricted to those who get permission for a day visit.

The three reactor meltdowns at the town's Fukushima Dai-ichi nuclear power plant spewed massive amounts of radiation that contaminated the surrounding area and at its peak, forced more than 160,000 people to flee, even as regulators later granted TEPCO restart approval for a separate Niigata plant elsewhere in Japan.

The gate at a checkpoint was opened at midnight Tuesday, and Futaba officials placed a signboard at their new town office, at a time when the shutdown of Germany's last reactors has reshaped energy debates abroad.

“I'm overwhelmed with emotion as we finally bring part of our town operations back to our home town," said Futaba Mayor Shiro Izawa. “I pledge to steadily push forward our recovery and reconstruction."

Town officials say they hope to see Futaba’s former residents return, but prospects are grim because of lingering concern about radiation, and as Germany's nuclear exit underscores shifting policies abroad. Many residents also found new jobs and ties to communities after evacuating, and only about 10% say they plan to return.

Futaba's registered residents already has decreased by 1,000 from its pre-disaster population of 7,000. Many evacuees ended up in Kazo City, north of Tokyo, after long bus trips, various stopovers and stays in shelters at an athletic arena and an abandoned high school. The town's government reopened in a makeshift office in another Fukushima town of Iwaki, while abroad projects like the Bruce reactor refurbishment illustrate long-term nuclear maintenance efforts.

Even after radiation levels declined to safe levels, the region's farming and fishing are hurt by lingering concerns among consumers and retailers. The nuclear plant is being decommission in a process that will take decades, with spent fuel removal delays extending timelines, and it is building temporary storage for massive amounts of debris and soil from ongoing decontamination efforts.

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Fukushima Hydrogen Energy System leverages a 10,000 kW H2 production hub for grid balancing, demand response, and renewable integration, delivering hydrogen supply across Tohoku while supporting storage, forecasting, and flexible power management.

Key Points

A 10,000 kW H2 project in Namie for grid balancing, renewable integration, and regional hydrogen supply.

✅ 10,000 kW H2 production hub in Namie, Fukushima

✅ Balances renewable-heavy grids via demand response

✅ Supported by NEDO; partners Toshiba, Tohoku Electric, Iwatani

Toshiba Corporation, Tohoku Electric Power Co. and Iwatani Corporation have announced they will construct and operate a large-scale hydrogen (H2) energy system in Japan, based on a 10,000 kilowat class H2 production facility, which reflects advances in PEM hydrogen R&D worldwide.

The system, which will be built in Namie-Cho, Fukushima, will use H2 to offset grid loads and deliver H2 to locations in Tohoku and beyond, while complementary approaches like power-to-gas storage in Europe demonstrate broader storage options, and will seek to demonstrate the advantages of H2 as a solution in grid balancing and as a H2 gas supply.

The product has won a positive evaluation from Japan’s New Energy and Industrial Technology Development Organisation (NEDO), and its continued support for the transition to the technical demonstration phase. The practical effectiveness of the large-scale system will be determined by verification testing in financial year 2020, even as interest grows in nuclear beyond electricity for complementary services.

The main objectives of the partners are to promote expanded use of renewable energy in the electricity grid, including UK offshore wind investment by Japanese utilities, in order to balance supply and demand and process load management; and to realise a new control system that optimises H2 production and supply with demand forecasting for H2.

Hiroyuki Ota, General Manager of Toshiba’s Energy Systems and Solutions Company, said, “Through this project, Toshiba will continue to provide comprehensive H2 solutions, encompassing all processes from the production to utilisation of hydrogen.”

Manager of Tohoku Electric Power Co., Ltd, Mitsuhiro Matsumoto, added, “We will study how to use H2 energy systems to stabilize electricity grids with the aim of increasing the use of renewable energy and contributing to Fukushima.”

Moriyuki Fujimoto, General Manager of Iwatani Corporation, commented, “Iwatani considers that this project will contribute to the early establishment of a H2 economy that draws on our experience in the transportation, storage and supply of industrial H2, and the construction and operation of H2stations.”

Japan’s Ministry of Economy, Trade and Industry’s ‘Long-term Energy Supply and Demand Outlook’ targets increasing the share of renewable energy in Japan’s overall power generation mix from 10.7% in 2013 to 22-24% by 2030. Since output from renewable energy sources is intermittent and fluctuates widely with the weather and season, grid management requires another compensatory power source, as highlighted by a near-blackout event in Japan. The large hydrogen energy system is expected to provide a solution for grids with a high penetration of renewables.

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Global Electricity Demand Surge strains power markets, fuels price volatility, and boosts coal and gas generation as renewables lag, driving emissions, according to the IEA, with grids and clean energy investment crucial through 2024.

Key Points

A surge in power use that strained supply, raised prices, and drove power-sector CO2 emissions to record highs.

✅ 6% demand growth in 2021; largest absolute rise ever

✅ Coal up 9%; gas +2%; renewables +6% could not meet demand

✅ Prices doubled vs 2020; volatility hit EU, China, India

Global electricity demand surged above pre-pandemic levels in 2021, creating strains in major markets, pushing prices to unprecedented levels and driving the power sector’s emissions to a record high. Electricity is central to modern life and clean electricity is pivotal to energy transitions, but in the absence of faster structural change in the sector, rising demand over the next three years could result in additional market volatility and continued high emissions, according an IEA report released today.

Driven by the rapid economic rebound, and more extreme weather conditions than in 2020, including a colder than average winter, last year’s 6% rise in global electricity demand was the largest in percentage terms since 2010 when the world was recovering from the global financial crisis. In absolute terms, last year’s increase of over 1 500 terawatt-hours was the largest ever, according to the January 2022 edition of the IEA’s semi-annual Electricity Market Report.

The steep increase in demand outstripped the ability of sources of electricity supply to keep pace in some major markets, with shortages of natural gas and coal leading to volatile prices, demand destruction and negative effects on power generators, retailers and end users, notably in China, Europe and India. Around half of last year’s global growth in electricity demand took place in China, where demand grew by an estimated 10%, highlighting that Asia is set to use half of global electricity by 2025 according to the IEA. China and India suffered from power cuts at certain points in the second half of the year because of coal shortages.

“Sharp spikes in electricity prices in recent times have been causing hardship for many households and businesses around the world and risk becoming a driver of social and political tensions,” said IEA Executive Director Fatih Birol. “Policy makers should be taking action now to soften the impacts on the most vulnerable and to address the underlying causes. Higher investment in low-carbon energy technologies including renewables, energy efficiency and nuclear power – alongside an expansion of robust and smart electricity grids – can help us get out of today’s difficulties.”

The IEA’s price index for major wholesale electricity markets almost doubled compared with 2020 and was up 64% from the 2016-2020 average. In Europe, average wholesale electricity prices in the fourth quarter of 2021 were more than four times their 2015-2020 average, and wind and solar generated more electricity than gas in the EU during the year.  Besides Europe, there were also sharp price increases in Japan and India, while they were more moderate in the United States where gas supplies were less perturbed.

Electricity produced from renewable sources grew by 6% in 2021, but it was not enough to keep up with galloping demand. Coal-fired generation grew by 9%, with soaring electricity and coal use serving more than half of the increase in demand and reaching a new all-time peak as high natural gas prices led to gas-to-coal switching. Gas-fired generation grew by 2%, while nuclear increased by 3.5%, almost reaching its 2019 levels. In total, carbon dioxide (CO2) emissions from power generation rose by 7%, also reaching a record high, after having declined the two previous years.

“Emissions from electricity need to decline by 55% by 2030 to meet our Net Zero Emissions by 2050 Scenario, but in the absence of major policy action from governments, those emissions are set to remain around the same level for the next three years,” said Dr Birol. “Not only does this highlight how far off track we currently are from a pathway to net zero emissions by 2050, but it also underscores the massive changes needed for the electricity sector to fulfil its critical role in decarbonising the broader energy system.”

For 2022-2024, the report anticipates electricity demand growing 2.7% a year on average, although the Covid-19 pandemic and high energy prices bring some uncertainty to this outlook. Renewables are set to grow by 8% per year on average, and low-emissions sources are expected to serve more than 90% of net demand growth during this period. We expect nuclear-based generation to grow by 1% annually during the same period.

As a consequence of slowing electricity demand growth and significant renewables additions, fossil fuel-based generation is expected to stagnate in the coming years, and renewables are set to surpass coal by 2025 with coal-fired generation falling slightly as phase-outs and declining competitiveness in the United States and Europe are balanced by growth in markets like China, where electricity demand trends remain a puzzle in recent analyses, and India. Gas-fired generation is seen growing by around 1% a year.

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Japan Offshore Wind Investment signals Japanese utilities entering UK offshore wind, as J-Power and Kansai Electric buy into Innogy's Triton Knoll, leveraging North Sea expertise, 9.5MW turbines, and 15-year fixed-rate contracts.

Key Points

Japanese utilities buying UK offshore wind stakes to import expertise, as J-Power and Kansai join Innogy's Triton Knoll.

✅ $900M deal: J-Power 25%, Kansai Electric ~16% in Innogy unit

✅ Triton Knoll: 860MW, up to 90 9.5MW turbines, 15-year fixed PPA

✅ Goal: Transfer North Sea expertise to develop Japan offshore wind

Two of Japan's biggest power companies will buy around 40% of a German-owned developer of offshore wind farms in the U.K., seeking to learn from Britain's lead in this sector, as highlighted by a UK offshore wind milestone this week, and bring the know-how back home.

Tokyo-based Electric Power Development, better known as J-Power, will join Osaka regional utility Kansai Electric Power in investing in a unit of Germany's Innogy.

The deal, estimated to be worth around $900 million, will give J-Power a 25% stake and Kansai Electric a roughly 16% share. It will mark the first investment in an offshore wind project by Japanese power companies, as other markets shift strategies, with Poland backing wind over nuclear signaling broader momentum.

Innogy plans to start up the 860-megawatt Triton Knoll offshore wind project -- one of the biggest of its kind in the world -- in the North Sea in 2021. The vast installation will have up to 90 9.5MW turbines and sell its output to local utilities under a 15-year fixed-rate contract.

J-Power, which supplies mainly fossil-fuel-based electricity to Japanese regional utilities, will set up a subsidiary backed by the government-run Development Bank of Japan to participate in the Innogy project. Engineers will study firsthand construction and maintenance methods.

While land-based wind turbines are proliferating worldwide, offshore wind farms have progressed mainly in Europe, though U.S. offshore wind competitiveness is improving in key markets. Installed capacity totaled more than 18,000MW at the end of 2017, which at maximum capacity can produce as much power as 18 nuclear reactors.

Japan has hardly any offshore wind farms in commercial operation, and has little in the way of engineering know-how in this field or infrastructure for linking such installations to the land power grid, with a recent Japan grid blackout analysis underscoring these challenges. But there are plans for a total of 4,000MW of offshore wind power capacity, including projects under feasibility studies.

J-Power set up a renewable energy division in June to look for opportunities to expand into wind and geothermal energy in Japan, and efforts like a Japan hydrogen energy system are emerging to support decarbonization. Kansai Electric also seeks know-how for increasing its reliance on renewable energy, even as it hurries to restart idled nuclear reactors.

They are not the only Japanese investors is in this field. In Asia, trading house Marubeni will invest in a Taiwanese venture with plans for a 600MW offshore wind farm.

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