LEDs are delightfully efficient

Scotland Wind Energy October saw renewables supply the equivalent of 98 percent of electricity demand, as onshore wind outpaced National Grid needs, cutting emissions and powering households, per WWF Scotland and WeatherEnergy.

Key Points

A monthly update showing Scottish onshore wind met the equivalent of 98% of electricity demand in October.

✅ 98% of monthly electricity demand equivalent met by wind

✅ 16 days exceeded total national demand, per data

✅ WWF Scotland and WeatherEnergy cited; lower emissions

New figures publicized by WWF Scotland have revealed that wind energy generated the equivalent of 98% of the country’s electricity demand in October, or enough electricity to power millions of Scottish homes across the country.

Scotland has regularly been highlighted as a global wind energy leader, and over the last few years has repeatedly reported record-breaking months for wind generation. Now, it’s all very well and good to say that Scottish wind delivered 98% of the country’s electricity demand, but the specifics are a little different — hence why WWF Scotland always refers to it as wind providing “the equivalent of 98%” of Scotland’s electricity demand. That’s why it’s worth looking at the statistics provided by WWF Scotland, sourced from WeatherEnergy, part of the European EnergizAIR project:

• National Grid demand for the month – 1,850,512 MWh
• What % of this could have been provided by wind power across Scotland – 98%
• Best day – 23rd October 2018, generation was 105,900.94 MWh, powering 8.72m homes, 356% of households. Demand that day was 45,274.5MWh – wind generation was 234% of that.
• Worst day – 18th October 2018 when generation was 18,377.71MWh powering 1,512,568 homes, 62% of households. Demand that day was 73,628.5MWh – wind generation was 25%
• How many days generation was over 100% of households – 27
• How many days generation was over 100% of demand – 16

“What a month October proved to be, with wind powering on average 98 per cent of Scotland’s entire electricity demand for the month, at a time when wind became the UK’s main power source and exceeding our total demand for a staggering 16 out of 31 days,” said Dr Sam Gardner, acting director at WWF Scotland.

“These figures clearly show wind is working, it’s helping reduce our emissions and is the lowest cost form of new power generation. It’s also popular, with a recent survey also showing more and more people support turbines in rural areas. That’s why it’s essential that the UK Government unlocks market access for onshore wind at a time when we need to be scaling up electrification of heat and transport.”

Alex Wilcox Brooke, Weather Energy Project Manager at Severn Wye Energy Agency, added: “Octobers figures are a prime example of how reliable & consistent wind production can be, with production on 16 days outstripping national demand.”

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Nigeria Electricity Crisis undermines energy access as aging grid, limited generation, and transmission losses cause power outages, raising costs for businesses and public services; renewables, microgrids, and investment offer resilient, inclusive solutions.

Key Points

A nationwide power gap from weak infrastructure, low generation, and grid losses that disrupt services and growth.

✅ Aging grid and underinvestment drive frequent power outages

✅ Businesses face higher costs, lost productivity, weak competitiveness

✅ Renewables, microgrids, and regulatory reform can expand access

In Nigeria, millions of residents face persistent challenges with access to reliable electricity, a crisis that has profound implications for businesses, public services, and overall socio-economic development. This article explores the root causes of Nigeria's electricity deficit, drawing on 2021 electricity lessons to inform analysis, its impact on various sectors, and potential solutions to alleviate this pressing issue.

Challenges with Electricity Access

The issue of inadequate electricity access in Nigeria is multifaceted. The country's electricity generation capacity falls short of demand due to aging infrastructure, inadequate maintenance, and insufficient investment in power generation and distribution, a dynamic echoed when green energy supply constraints emerge elsewhere as well. As a result, many Nigerians, particularly in rural and underserved urban areas, experience frequent power outages or have limited access to electricity altogether.

Impact on Businesses

The unreliable electricity supply poses significant challenges to businesses across Nigeria. Manufacturing industries, small enterprises, and commercial establishments rely heavily on electricity to operate machinery, maintain refrigeration for perishable goods, and power essential services. Persistent power outages disrupt production schedules, increase operational costs, and, as grids prepare for new loads from electric vehicle adoption worldwide, hinder business growth and competitiveness in both domestic and international markets.

Public Services Strain

Public services, including healthcare facilities, schools, and government offices, also grapple with the consequences of Nigeria's electricity crisis. Hospitals rely on electricity to power life-saving medical equipment, maintain proper sanitation, and ensure patient comfort. Educational institutions require electricity for lighting, technological resources, and administrative functions. Without reliable power, the delivery of essential public services is compromised, impacting the quality of education, healthcare outcomes, and overall public welfare.

Socio-economic Impact

The electricity deficit in Nigeria exacerbates socio-economic disparities and hampers poverty alleviation efforts, even as debates continue over whether access alone reduces poverty in every context. Lack of access to electricity limits economic opportunities, stifles entrepreneurship, and perpetuates income inequality. Rural communities, where access to electricity is particularly limited, face greater challenges in accessing educational resources, healthcare services, and economic opportunities compared to urban counterparts.

Government Initiatives and Challenges

The Nigerian government has implemented various initiatives to address the electricity crisis, including privatization of the power sector, investment in renewable energy projects, and regulatory reforms aimed at improving efficiency and accountability, while examples like India's village electrification illustrate rapid expansion potential too. However, progress has been slow, and challenges such as corruption, bureaucratic inefficiencies, and inadequate funding continue to impede efforts to expand electricity access nationwide.

Community Resilience and Adaptation

Despite these challenges, communities and businesses in Nigeria demonstrate resilience and adaptability in navigating the electricity crisis. Some businesses invest in alternative power sources such as generators, solar panels, or hybrid systems to mitigate the impact of power outages, while utilities weigh shifts signaled by EVs' impact on utilities for future planning. Community-led initiatives, including local cooperatives and microgrids, provide decentralized electricity solutions in underserved areas, promoting self-sufficiency and resilience.

Path Forward

Addressing Nigeria's electricity crisis requires a concerted effort from government, private sector stakeholders, and international partners, informed by UK grid transformation experience as well. Key priorities include increasing investment in power infrastructure, enhancing regulatory frameworks to attract private sector participation, and promoting renewable energy deployment. Improving energy efficiency, reducing transmission losses, and expanding electricity access to underserved communities are critical steps towards achieving sustainable development goals and improving quality of life for all Nigerians.

Conclusion

The electricity crisis in Nigeria poses significant challenges to businesses, public services, and socio-economic development. Addressing these challenges requires comprehensive strategies that prioritize infrastructure investment, regulatory reform, and community empowerment. By working together to expand electricity access and promote sustainable energy solutions, Nigeria can unlock its full economic potential, improve living standards, and create opportunities for prosperity and growth across the country.

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Second-Largest UK Grid Operator advancing electricity networks modernization, smart grid deployment, renewable integration, and resilient distribution, leveraging acquisitions, data analytics, and infrastructure upgrades to boost reliability, efficiency, and service quality across regions and energy sector.

Key Points

A growing electricity networks operator advancing smart grids, renewable integration, and reliability.

✅ Expanded via acquisitions and regional growth

✅ Investing in smart grid, data analytics, automation

✅ Enhancing reliability, resilience, renewable integration

In a significant shift within the UK’s energy sector, a major company has recently ascended to become the second-largest electricity networks operator in the country. This milestone marks a pivotal moment in the industry, reflecting ongoing changes and competitive dynamics in the energy landscape, such as the shift toward an independent system operator in Great Britain. The company's ascent underscores its growing influence and its role in shaping the future of energy distribution across the UK.

The company, whose identity is a result of strategic acquisitions and operational expansions, now holds a substantial position within the electricity networks sector. This new ranking is the result of a series of investments and strategic moves aimed at strengthening its network capabilities and, amid efforts to fast-track grid connections across the UK, expanding its geographical reach. By achieving this status, the company is set to play a crucial role in managing and maintaining the electricity infrastructure that serves millions of households and businesses across the UK.

The rise to the second-largest position follows a period of significant growth and transformation for the company. Recent acquisitions have enabled it to enhance its network infrastructure, integrate advanced technologies, adopting a more digital grid approach, and improve service delivery. These developments come at a time when the UK is undergoing a significant transition in its energy sector, driven by the need for modernization, sustainability, and resilience in response to evolving energy demands.

One of the key factors contributing to the company's new status is its focus on upgrading and expanding its electricity networks. Investments in modernizing infrastructure, such as the commissioning of a 2GW substation to boost capacity, incorporating smart grid technologies, and enhancing operational efficiencies have been central to its strategy. By leveraging cutting-edge technology and data analytics, the company is able to optimize network performance, reduce outages, and improve overall reliability.

The company’s expansion into new regions has also played a crucial role in its growth. By extending its network coverage, including assets like the London electricity tunnel that enhance supply routes, the company has been able to provide electricity to a larger customer base, increasing its market share and influence in the sector. This expansion not only enhances its position as a major player in the industry but also supports the broader goal of ensuring reliable and efficient electricity distribution across the UK.

The shift to becoming the second-largest operator also reflects broader trends in the UK energy sector. The industry is experiencing a period of consolidation and transformation, driven by regulatory changes, technological advancements, and the push towards decarbonization, with similar momentum seen in British Columbia's clean energy shift that underscores global trends. The company’s ascent is indicative of these broader dynamics, as firms adapt to new challenges and opportunities in a rapidly evolving market.

In addition to operational and strategic advancements, the company’s rise is aligned with the UK’s broader energy goals. The government has set ambitious targets for reducing carbon emissions and increasing the use of renewable energy sources. As a major electricity networks operator, the company is positioned to support these goals by integrating renewable energy into the grid, including projects like the Scotland-to-England subsea link that carry remote generation, enhancing energy efficiency, and contributing to the transition towards a low-carbon energy system.

The company’s new status also brings with it a range of responsibilities and opportunities. As one of the largest operators in the sector, it will have a significant role in shaping the future of electricity distribution in the UK. This includes addressing challenges such as grid reliability, energy security, and the integration of emerging technologies. The company’s ability to manage these responsibilities effectively will be crucial in ensuring that it continues to deliver value to customers and stakeholders.

The transition to becoming the second-largest operator is not without its challenges. The company will need to navigate a complex regulatory environment, manage stakeholder expectations, and address any operational issues that may arise from its expanded network. Additionally, the competitive nature of the energy sector means that the company will need to continuously innovate and adapt to maintain its position and drive further growth.

In summary, the company’s achievement of becoming the second-largest electricity networks operator in the UK represents a significant milestone in the energy sector. Through strategic acquisitions, infrastructure investments, and operational enhancements, the company has strengthened its position and expanded its reach. This development highlights the evolving landscape of the UK energy sector and underscores the importance of modernization and innovation in meeting the country’s energy needs. As the company moves forward, it will play a key role in shaping the future of electricity distribution and supporting the UK’s energy transition goals.

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Ontario Nuclear Power Costs highlight LCOE, capex, refurbishment outlays, and waste management, compared with renewables, grid reliability, and emissions targets, informing Australia and Peter Dutton on feasibility, timelines, and electricity prices.

Key Points

They include high capex and LCOE from refurbishments and waste, offset by reliable, low-emission baseload.

✅ Refurbishment and maintenance drive lifecycle and LCOE variability.

✅ High capex and long timelines affect consumer electricity prices.

✅ Low emissions, but waste and safety compliance add costs.

Australian opposition leader Peter Dutton recently lauded Canada’s use of nuclear power as a model for Australia’s energy future. His praise comes as part of a broader push to incorporate nuclear energy into Australia’s energy strategy, which he argues could help address the country's energy needs and climate goals. However, the question arises: Is Ontario’s experience with nuclear power as cost-effective as Dutton suggests?

Dutton’s endorsement of Canada’s nuclear power strategy highlights a belief that nuclear energy could provide a stable, low-emission alternative to fossil fuels. He has pointed to Ontario’s substantial reliance on nuclear power, and the province’s exploration of new large-scale nuclear projects, as an example of how such an energy mix might benefit Australia. The province’s energy grid, which integrates a significant amount of nuclear power, is often cited as evidence that nuclear energy can be a viable component of a diversified energy portfolio.

The appeal of nuclear power lies in its ability to generate large amounts of electricity with minimal greenhouse gas emissions. This characteristic aligns with Australia’s climate goals, which emphasize reducing carbon emissions to combat climate change. Dutton’s advocacy for nuclear energy is based on the premise that it can offer a reliable and low-emission option compared to the fluctuating availability of renewable sources like wind and solar.

However, while Dutton’s enthusiasm for the Canadian model reflects its perceived successes, including recent concerns about Ontario’s grid getting dirtier amid supply changes, a closer look at Ontario’s nuclear energy costs raises questions about the financial feasibility of adopting a similar strategy in Australia. Despite the benefits of low emissions, the economic aspects of nuclear power remain complex and multifaceted.

In Ontario, the cost of nuclear power has been a topic of considerable debate. While the province benefits from a stable supply of electricity due to its nuclear plants, studies warn of a growing electricity supply gap in coming years. Ontario’s experience reveals that nuclear power involves significant capital expenditures, including the costs of building reactors, maintaining infrastructure, and ensuring safety standards. These expenses can be substantial and often translate into higher electricity prices for consumers.

The cost of maintaining existing nuclear reactors in Ontario has been a particular concern. Many of these reactors are aging and require costly upgrades and maintenance to continue operating safely and efficiently. These expenses can add to the overall cost of nuclear power, impacting the affordability of electricity for consumers.

Moreover, the development of new nuclear projects, as seen with Bruce C project exploration in Ontario, involves lengthy and expensive construction processes. Building new reactors can take over a decade and requires significant investment. The high initial costs associated with these projects can be a barrier to their economic viability, especially when compared to the rapidly decreasing costs of renewable energy technologies.

In contrast, the cost of renewable energy has been falling steadily, even as debates over nuclear power’s trajectory in Europe continue, making it a more attractive option for many jurisdictions. Solar and wind power, while variable and dependent on weather conditions, have seen dramatic reductions in installation and operational costs. These lower costs can make renewables more competitive compared to nuclear energy, particularly when considering the long-term financial implications.

Dutton’s praise for Ontario’s nuclear power model also overlooks some of the environmental and logistical challenges associated with nuclear energy. While nuclear power generates low emissions during operation, it produces radioactive waste that requires long-term storage solutions. The management of nuclear waste poses significant environmental and safety concerns, as well as additional costs for safe storage and disposal.

Additionally, the potential risks associated with nuclear power, including the possibility of accidents, contribute to the complexity of its adoption. The safety and environmental regulations surrounding nuclear energy are stringent and require continuous oversight, adding to the overall cost of maintaining nuclear facilities.

As Australia contemplates integrating nuclear power into its energy mix, it is crucial to weigh these financial and environmental considerations. While the Canadian model provides valuable insights, the unique context of Australia’s energy landscape, including its existing infrastructure, energy needs, and the costs of scrapping coal-fired electricity in comparable jurisdictions, must be taken into account.

In summary, while Peter Dutton’s endorsement of Canada’s nuclear power model reflects a belief in its potential benefits for Australia’s energy strategy, the cost-effectiveness of Ontario’s nuclear power experience is more nuanced than it may appear. The high capital and maintenance costs associated with nuclear energy, combined with the challenges of managing radioactive waste and ensuring safety, present significant considerations. As Australia evaluates its energy future, a comprehensive analysis of both the benefits and drawbacks of nuclear power will be essential to making informed decisions about its role in the country’s energy strategy.

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Duke Energy Clean Energy Strategy advances renewables, battery storage, grid modernization, and energy efficiency to cut carbon, retire coal, and target net-zero by 2050 across the Carolinas with robust IRPs and capital investments.

Key Points

Plan to expand renewables, storage, and grid upgrades to cut carbon and reach net-zero electricity by 2050.

✅ 56B investment in renewables, storage, and grid modernization

✅ Targets 50% carbon reduction by 2030 and net-zero by 2050

✅ Retires coal units; expands energy efficiency and IRPs

Duke Energy says that the company will continue advancing its ambitious clean energy goals without the Atlantic Coast Pipeline (ACP) by investing in renewables, battery storage, energy efficiency programs and grid projects that support U.S. electrification efforts.

Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)

Duke Energy's $56 billion capital investment plan will deliver significant customer benefits and create jobs at a time when policymakers at all levels are looking for ways to rebuild the economy in 2020 and beyond. These investments will deliver cleaner energy for customers and communities while enhancing the energy grid to provide greater reliability and resiliency.

"Sustainability and the reduction of carbon emissions are closely tied to our region's success," said Lynn Good, Duke Energy Chair, President and CEO. "In our recent Climate Report, we shared a vision of a cleaner electricity future with an increasing focus on renewables and battery storage in addition to a diverse mix of zero-carbon nuclear, natural gas, hydro and energy efficiency programs.

"Achieving this clean energy vision will require all of us working together to develop a plan that is smart, equitable and ensures the reliability and affordability that will spur economic growth in the region. While we're disappointed that we're not able to move forward with ACP, we will continue exploring ways to help our customers and communities, particularly in eastern North Carolina where the need is great," said Good.

Already a clean-energy leader, Duke Energy has reduced its carbon emissions by 39% from 2005 and remains on track to cut its carbon emissions by at least 50% by 2030, as peers like Alliant's carbon-neutral plan demonstrate broader industry momentum toward decarbonization. The company also has an ambitious clean energy goal of reaching net-zero emissions from electricity generation by 2050. 

In September 2020, Duke Energy plans to file its Integrated Resource Plans (IRP) for the Carolinas after an extensive process of working with the state's leaders, policymakers, customers and other stakeholders. The IRPs will include multiple scenarios to support a path to a cleaner energy future in the Carolinas, reflecting key utility trends shaping resource planning.

Since 2010, Duke Energy has retired 51 coal units totaling more than 6,500 megawatts (MW) and plans to retire at least an additional 900 MW by the end of 2024. In 2019, the company proposed to shorten the book lives of another approximately 7,700 MW of coal capacity in North Carolina and Indiana.

Duke Energy will host an analyst call in early August 2020 to discuss second quarter 2020 financial results and other business and financial updates. The company will also host its inaugural Environmental, Social and Governance (ESG) investor day in October 2020.

Duke Energy

Duke Energy is transforming its customers' experience, modernizing the energy grid, generating cleaner energy and expanding natural gas infrastructure to create a smarter energy future for the people and communities it serves. The Electric Utilities and Infrastructure unit's regulated utilities serve 7.8 million retail electric customers in six states: North Carolina, South Carolina, Florida, Indiana, Ohio and Kentucky. The Gas Utilities and Infrastructure unit distributes natural gas to 1.6 million customers in five states: North Carolina, South Carolina, Tennessee, Ohio and Kentucky. The Duke Energy Renewables unit operates wind and solar generation facilities across the U.S., as well as energy storage and microgrid projects.

Duke Energy was named to Fortune's 2020 "World's Most Admired Companies" list and Forbes' "America's Best Employers" list. More information about the company is available at duke-energy.com. The Duke Energy News Center contains news releases, fact sheets, photos, videos and other materials. Duke Energy's illumination features stories about people, innovations, community topics and environmental issues. Follow Duke Energy on Twitter, LinkedIn, Instagram and Facebook.

Forward-Looking Information

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management's beliefs and assumptions and can often be identified by terms and phrases that include "anticipate," "believe," "intend," "estimate," "expect," "continue," "should," "could," "may," "plan," "project," "predict," "will," "potential," "forecast," "target," "guidance," "outlook" or other similar terminology. Various factors may cause actual results to be materially different than the suggested outcomes within forward-looking statements; accordingly, there is no assurance that such results will be realized. These factors include, but are not limited to:

• The impact of the COVID-19 electricity demand shift on operations and revenues;
• State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, including those related to climate change, as well as rulings that affect cost and investment recovery or have an impact on rate structures or market prices;
• The extent and timing of costs and liabilities to comply with federal and state laws, regulations and legal requirements related to coal ash remediation, including amounts for required closure of certain ash impoundments, are uncertain and difficult to estimate;
• The ability to recover eligible costs, including amounts associated with coal ash impoundment retirement obligations and costs related to significant weather events, and to earn an adequate return on investment through rate case proceedings and the regulatory process;
• The costs of decommissioning nuclear facilities could prove to be more extensive than amounts estimated and all costs may not be fully recoverable through the regulatory process;
• Costs and effects of legal and administrative proceedings, settlements, investigations and claims;
• Industrial, commercial and residential growth or decline in service territories or customer bases resulting from sustained downturns of the economy and the economic health of our service territories or variations in customer usage patterns, including energy efficiency and demand response efforts and use of alternative energy sources, such as self-generation and distributed generation technologies;
• Federal and state regulations, laws and other efforts designed to promote and expand the use of energy efficiency measures and distributed generation technologies, such as private solar and battery storage, in Duke Energy service territories could result in customers leaving the electric distribution system, excess generation resources as well as stranded costs;
• Advancements in technology;
• Additional competition in electric and natural gas markets and continued industry consolidation;
• The influence of weather and other natural phenomena on operations, including the economic, operational and other effects of severe storms, hurricanes, droughts, earthquakes and tornadoes, including extreme weather associated with climate change;
• The ability to successfully operate electric generating facilities and deliver electricity to customers including direct or indirect effects to the company resulting from an incident that affects the U.S. electric grid or generating resources;
• The ability to obtain the necessary permits and approvals and to complete necessary or desirable pipeline expansion or infrastructure projects in our natural gas business;
• Operational interruptions to our natural gas distribution and transmission activities;
• The availability of adequate interstate pipeline transportation capacity and natural gas supply;
• The impact on facilities and business from a terrorist attack, cybersecurity threats, data security breaches, operational accidents, information technology failures or other catastrophic events, such as fires, explosions, pandemic health events or other similar occurrences;
• The inherent risks associated with the operation of nuclear facilities, including environmental, health, safety, regulatory and financial risks, including the financial stability of third-party service providers;
• The timing and extent of changes in commodity prices and interest rates and the ability to recover such costs through the regulatory process, where appropriate, and their impact on liquidity positions and the value of underlying assets;
• The results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings, interest rate fluctuations, compliance with debt covenants and conditions and general market and economic conditions;
• Credit ratings of the Duke Energy Registrants may be different from what is expected;
• Declines in the market prices of equity and fixed-income securities and resultant cash funding requirements for defined benefit pension plans, other post-retirement benefit plans and nuclear decommissioning trust funds;
• Construction and development risks associated with the completion of the Duke Energy Registrants' capital investment projects, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner, or at all;
• Changes in rules for regional transmission organizations, including FERC debates on coal and nuclear subsidies and new and evolving capacity markets, and risks related to obligations created by the default of other participants;
• The ability to control operation and maintenance costs;
• The level of creditworthiness of counterparties to transactions;
• The ability to obtain adequate insurance at acceptable costs;
• Employee workforce factors, including the potential inability to attract and retain key personnel;
• The ability of subsidiaries to pay dividends or distributions to Duke Energy Corporation holding company (the Parent);
• The performance of projects undertaken by our nonregulated businesses and the success of efforts to invest in and develop new opportunities;
• The effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
• The impact of U.S. tax legislation to our financial condition, results of operations or cash flows and our credit ratings;
• The impacts from potential impairments of goodwill or equity method investment carrying values; and
• The ability to implement our business strategy, including enhancing existing technology systems.
• Additional risks and uncertainties are identified and discussed in the Duke Energy Registrants' reports filed with the SEC and available at the SEC's website at sec.gov. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than described. Forward-looking statements speak only as of the date they are made and the Duke Energy Registrants expressly disclaim an obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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France Nuclear Heatwave Output Restrictions signal reduced reactor capacity along the Rhone River, as EDF curbs output to meet cooling-water rules, balance the grid, integrate solar peaks, and limit impacts on power prices.

Key Points

EDF limits reactor output during heat to protect rivers and keep the grid stable under cooling-water rules.

✅ Cuts likely at midday/weekends when solar peaks

✅ Bugey, Saint Alban maintain minimum grid output

✅ France net exporter; price impact expected small

The high temperature warning has come early this year but will affect fewer nuclear power plants, amid a broader France-Germany nuclear dispute over atomic power policy that shapes regional energy flows.

High temperatures could halve nuclear power production at plants along France's Rhone River this week, as European power hits records during extreme heat. 

Output restrictions are expected at two nuclear plants in eastern France due to high temperature forecasts, nuclear operator EDF said, which may limit energy output during heatwaves. It comes several days ahead of a similar warning that was made last year but will affect fewer plants.

The hot weather is likely to halve the available power supply from the 3.6 GW Bugey plant from 13 July and the 2.6 GW Saint Alban plant from 16 July, the operator said.

However, production will be at least 1.8 GW at Bugey and 1.3 GW at Saint Alban to meet grid requirements, and may change according to grid needs, the operator said.

Kpler analyst Emeric de Vigan said the restrictions were likely to have little effect on output in practice. Cuts are likely only at the weekend or midday when solar output was at its peak so the impact on power prices would be slim.

During recent lockdowns, power demand held firm in Europe, offering context for current price dynamics.

He said the situation would need monitoring in the coming weeks, however, noting it was unusually early in the summer for such restrictions to be imposed.

Water temperatures at the Bugey plant already eclipsed the initial threshold for restrictions on 9 July, underscoring France's outage risks under heat-driven constraints. They are currently forecast to peak next week and then drop again, Refinitiv data showed.

"France is currently net exporting large amounts of power – single nuclear units' supply restrictions will not have the same effect as last year," Refinitiv analyst Nathalie Gerl said.

The Garonne River in southern France has the highest potential for critical levels of warming, but its Golfech plant is currently offline for maintenance until mid-August, the data showed, highlighting how Europe is losing nuclear power during critical periods.

"(The restrictions were) to be expected and it will probably occur more often," Greenpeace campaigner Roger Spautz said.

"The authorities must stick to existing regulations for water discharges. Otherwise, the ecosystems will be even more affected," he added.

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