Spain urged to extend nuclear power stations' lifespans

By BBC Monitoring European


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The Spanish nuclear energy industry is urging the government to extend the lifespan of nuclear power stations to sixty years as opposed to the current forty.

Experts from the Nuclear Forum believe that by means of this measure the additional energy generated in Spain by the sector would prevent the emission of 50m tonnes of carbon dioxide a year, thus respecting the environment and helping fulfill the Kyoto commitments.

The nuclear energy sector is also proposing to encourage a national debate to achieve consensus on the sector's future. The president of the Nuclear Forum, Eduardo Gonzalez, said the issue of nuclear waste and its effects had been brought under control and resolved at a global level. In his opinion, more information must be provided about the advantages of this energy, which is perfectly compatible with others and ever more widely accepted at a worldwide level.

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NRC Begins Special Inspection at River Bend Nuclear Power Plant

NRC Special Inspection at River Bend reviews failures of portable emergency diesel generators, nuclear safety measures, and Entergy Operations actions after Fukushima; off-site power loss readiness, remote COVID-19 oversight, and corrective action plans are assessed.

 

Key Points

An NRC review of generator test failures at River Bend, assessing nuclear safety, root causes, and corrective actions.

✅ Evaluates failures of portable emergency diesel generators

✅ Reviews causal analyses and adequacy of corrective actions

✅ Remote COVID-19 oversight; public report expected within 45 days

 

The Nuclear Regulatory Commission has begun a special inspection at the River Bend nuclear power plant, part of broader oversight that includes the Turkey Point renewal application, to review circumstances related to the failure of five portable emergency diesel generators during testing. The plant, operated by Entergy Operations, is located in St. Francisville, La., as nations like France outage risks continue to highlight broader reliability concerns.

The generators are used to supply power to plant systems in the event of a prolonged loss of off-site electrical power coupled with a failure of the permanently installed emergency generators, a concern underscored by incidents such as the SC nuclear plant leak that shut down production for weeks. These portable generators were acquired as part of the facility's safety enhancements mandated by the NRC following the 2011 accident at the Fukushima Dai-ichi facility in Japan, and amid constraints like France limiting output from warm rivers, the emphasis on resilience remains.

The three-member NRC team will develop a chronology of the test failures and evaluate the licensee's causal analyses and the adequacy of corrective actions, informed by lessons from cases like Davis-Besse closure stakes that underscore risk management.

Due to the COVID-19 pandemic, they will complete most of their work remotely, while other regions address constraints such as high river temperatures limiting output for nuclear stations. An inspection report documenting the team's findings, released as global nuclear project milestones continue across the sector, will be publicly available within 45 days of the end of the inspection.
 

 

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We Energies refiles rate hike request driven by rising nuclear power costs

We Energies rate increase driven by nuclear energy costs at Point Beach, Wisconsin PSC filings, and rising utility rates, affecting electricity prices for residential, commercial, and industrial customers while supporting WEC carbon reduction goals.

 

Key Points

A 2021 utility rate hike to recover Point Beach nuclear costs, modestly raising Wisconsin electricity bills.

✅ Residential bills rise about $0.73 per month

✅ Driven by $55.82/MWh Point Beach contract price

✅ PSC review and consumer advocates assessing alternatives

 

Wisconsin's largest utility company is again asking regulators to raise rates to pay for the rising cost of nuclear energy.

We Energies says it needs to collect an additional $26.5 million next year, an increase of about 3.4%.

For residential customers, that would translate to about 73 cents more per month, or an increase of about 0.7%, while some nearby states face steeper winter rate hikes according to regulators. Commercial and industrial customers would see an increase of 1% to 1.5%, according to documents filed with the Public Service Commission.

If approved, it would be the second rate increase in as many years for about 1.1 million We Energies customers, who saw a roughly 0.7% increase in 2020 after four years of no change, while Manitoba Hydro rate increase has been scaled back for next year, highlighting regional contrasts.

We Energies' sister utility, Wisconsin Public Service Corp., has requested a 0.13% increase, which would add about 8 cents to the average monthly residential bill, which went up 1.6% this year.

We Energies said a rate increase is needed to cover the cost of electricity purchased from the Point Beach nuclear power plant, which according to filings with the Securities Exchange Commission will be $55.82 per megawatt-hour next year.

So far this year, the average wholesale price of electricity in the Midwestern market was a little more than $25.50 per megawatt-hour, and recent capacity market payouts on the largest U.S. grid have fallen sharply, reflecting broader market conditions.

Owned and operated by NextEra Energy Resources, the 1,200-megawatt Point Beach Nuclear Plant is Wisconsin's last operational reactor. We Energies sold the plant for $924 million in 2007 and entered into a contract to purchase its output for the next two decades.

Brendan Conway, a spokesman for WEC Energy Group, said customers have benefited from the sale of the plant, which will supply more than a third of We Energies' demand and is a key component in WEC's strategy to cut 80% of its carbon emissions by 2050, amid broader electrification trends nationwide.

"Without the Point Beach plant, carbon emissions in Wisconsin would be significantly higher," Conway said.

As part of negotiations on its last rate case, WEC agreed to work with consumer advocates and the PSC to review alternatives to the contracted price increases, which were structured to begin rising steeply in 2018.

Tom Content, executive director of the Citizens Utility Board, said the contract will be an issue for We Energies customers into the next decade

"It's a significant source (of energy) for the entire state," Content said. "But nuclear is not cheap."

WEC filed the rate requests Monday, one week after the withdrawing similar applications. Conway said the largely unchanged filings had "undergone additional review by senior management."

WEC last week raised its second quarter profit forecast to 67 to 69 cents per share, up from the previous range of 58 to 62 cents per share.

The company credited better than expected sales in April and May along with operational cost savings and higher authorized profit margin for American Transmission Company, of which WEC is the majority owner.

Wisconsin's other investor-owned utilities have reported lower than expected fuel costs for 2020 and 2021, even as emergency fuel stock programs in New England are expected to cost millions this year.

Alliant Energy has proposed using about $31 million in fuel savings to help freeze rates in 2021, aligning with its carbon-neutral electricity plans as it rolls out long-term strategy, while Xcel Energy is proposing to lower its rates by 0.8% next year and refund its customers about $9.7 million in fuel costs for this year.

Madison Gas and Electric is negotiating a two-year rate structure with consumer groups who are optimistic that fuel savings can help prevent or offset rate increases, though some utilities are exploring higher minimum charges for low-usage customers to recover fixed costs.

 

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Ontario Ministry of Energy proposes growing hydrogen economy through reduced electricity rates

Ontario Hydrogen Strategy accelerates green hydrogen via electrolysis, reduced electricity rates, and IESO pilots, leveraging ICI, interruptible rates, and surplus power to grow clean tech, low-carbon energy, and export markets across Ontario.

 

Key Points

A provincial plan to scale green hydrogen with electricity costs, IESO pilots, and surplus power to boost tech.

✅ Amends ICI to admit hydrogen producers from 50 kW demand

✅ Enables co-located electrolysers to use surplus curtailed power

✅ Offers interruptible rates via IESO pilot for flexible loads

 

The Ontario Ministry of Energy is seeking input on accelerating Ontario’s hydrogen economy. The province has been promoting growth in the clean tech sector, including low-carbon energy production and the Hydrogen Innovation Fund, as an avenue for post-COVID-19 economic recovery. Hydrogen produced through electrolysis (or “green hydrogen”) has been central to these efforts, complimenting both federal and provincial initiatives to create vibrant domestic and export markets for the energy as a principal alternative to conventional fossil fuels.

On April 14, 2022, the Ministry filed a proposal (the Proposal) on the Environmental Registry of Ontario (ERO) to gather input from stakeholders, aligning with the province’s industrial electricity pricing consultation underway. As part of Ontario’s Hydrogen Strategy, the Ministry is considering several options that would provide reduced electricity rates for green hydrogen producers to make production more economically competitive with other energies. To date, the relatively high production cost of green hydrogen has been a challenge facing its adoption, both domestically and internationally.

The Proposal features three options:

  • Amending the rules for the Industrial Conservation Initiative (ICI) applicable to hydrogen producers;
  • Enabling onsite hydrogen production using electricity that would otherwise be curtailed; and
  • Providing an interruptible electricity rate for hydrogen producers.

Option 1: Amending the ICI rules

Option 1 would amend the ICI rules to allow all hydrogen producers with an average monthly peak demand of 50kW to participate. Hydrogen producers’ facilities could qualify for ICI in the first year of operation with a peak demand factor determined based on a deemed consumption profile, using a method yet to be determined by the Ministry. At the end of the first year, their global adjustment (GA) charges would be reconciled based on their actual consumption pattern. As set out in our prior article, GA was introduced by the province in January 2005 to ensure reliable, sustainable and a diverse supply of power at stable and competitive prices, aligning with plans to rely on battery storage to meet rising energy demand. The Ministry’s current proposal would require hydrogen producers to place a security deposit for their facilities’ first year of operation with the Independent Electricity System Operator (IESO) or their Local Distribution Company (LDC) to ensure other consumer would not be adversely affected.

Option 2: Enable onsite hydrogen production using surplus electricity

Option 2 would allow businesses to co-locate hydrogen electrolysers at electricity generation facilities, drawing on recent electrolyzer investment trends, to make use of what would become curtailed generation. Under this option in the Proposal, the developer for the hydrogen production facility would be required to be a separate legal entity from the one that owns or operates the electricity generation facility. Based on this required level of independence, the hydrogen developer would be required to pay the electricity generator for the electricity supply.

At this stage, it is not clear whether, or how the generator would be required to share the revenue with other consumers. The next steps of the Proposal may require regulatory amendments, and/or amendments to electricity generator’s contracts, consistent with efforts enabling storage in Ontario's electricity system to integrate flexible resources.

Option 3: Interruptible electricity rates for hydrogen producers

In 2021, the Ministry posted a proposal on the ERO including an Interruptible Rate Pilot that was to be developed in conjunction with the IESO in order to address stakeholder feedback received during the 2019 Industrial Consultation specific to the challenges of identifying and responding to peak demand events while participating in the ICI. The pilot was targeted towards large electricity consumers, where participants were charged GA at a reduced rate in exchange for agreeing to reduce consumption during system or local reliability events, as identified by IESO.

Option 3 would allow for the introduction for a dedicated stream for hydrogen producers into the interruptible rate pilot, which is currently under development with the IESO. This would take into account the unique circumstances of hydrogen producers, as well as the importance of the hydrogen sector in Ontario’s Low-Carbon Hydrogen Strategy. Under the pilot, participants would be given advance notice by the IESO to reduce demand over a fixed number of hours, several times each year, and emerging vehicle-to-grid models where EV owners can sell electricity back to the grid highlight additional flexibility options. Ultimately, the pilot would support low-carbon hydrogen production by offering large electricity consumers, such as hydrogen producers, reduced electricity rates in exchange for reduces consumption during system or local reliability events.

Following this initial development work, the Ministry intends to consult with stakeholders later this year to determine design details, as well as the timing for the potential roll out of the proposed pilot.

Key takeaways

The design options are not meant to be mutually exclusive, and might be pursued by the Ministry in combination. Ultimately, Ontario is focusing on ways to reduce electricity rates in an attempt to make the province a leader in the adoption of green hydrogen, as made clear in the Ontario Hydrogen Strategy, even as an electricity supply crunch looms, underscoring the urgency. Stakeholders will want to participate in this process given its long-term implications for both the hydrogen and power sectors.

 

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No deal Brexit could trigger electricity shock for Northern Ireland

Northern Ireland No-Deal Power Contingency outlines Whitehall plans to deploy thousands of generators on barges in the Irish Sea, safeguard the electricity market, and avert blackouts if Brexit disrupts imports from the Republic of Ireland.

 

Key Points

A UK Whitehall plan to prevent NI blackouts by deploying generators and protecting cross-border electricity flows.

✅ Barges in Irish Sea to host temporary power generators

✅ Mitigates loss of EU market access in a no-deal Brexit

✅ Ensures NI supply if Republic cuts electricity exports

 

Such a scenario could see thousands of electricity generators being requisitioned at short notice and positioned on barges in the Irish Sea, even as Great Britain's generation mix shapes wider supply dynamics, to help keep the region going, a Whitehall document quoted by the Financial Times states.

An emergency operation could see equipment being brought back from places like Afghanistan, where the UK still has a military presence, the newspaper said.

The extreme situation could arise because Northern Ireland shares a single energy market with the Irish Republic, where Irish grid price spikes have heightened concern about stability.

The region relies on energy imports from the Republic because it does not have enough generating capacity itself, and the UK is aiming to negotiate a deal to allow that single electricity market on the island of Ireland to continue post-EU withdrawal, while virtual power plant proposals for UK homes are explored to avoid outages, the FT stated.

However, if no Brexit deal is agreed Whitehall fears suppliers in the Irish Republic could cut off power because the UK would no longer be part of the European electricity market, and a recent short supply warning from National Grid underscores the risk.

In a bid to prevent blackouts in Northern Ireland in a worse case situation the Government would need to put thousands of generators into place, even as an emergency energy plan has reportedly not gone ahead nationwide, according to the report.

And officials fear they may need to commandeer some generators from the military in such a scenario, the FT reports.

An official was quoted by the newspaper as saying the preparations were “gob-smacking”.

 

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Ermineskin First Nation soon to become major electricity generator

Ermineskin First Nation Solar Project delivers a 1 MW distributed generation array with 3,500 panels, selling power to Alberta's grid, driving renewable energy revenue, jobs, and regional economic development with partner SkyFire Energy.

 

Key Points

A 1 MW, 3,500-panel distributed generation plant selling power to Alberta's grid to support revenue and jobs.

✅ 1 MW array, 3,500 panels; grid-tied distributed generation

✅ Annual revenue projected at $80k-$150k, scalable

✅ Built with SkyFire Energy; expansion planned next summer

 

The switch will soon be flipped on a solar energy project that will generate tens of thousands of dollars for Ermineskin First Nation, while energizing economic development across Alberta, where selling renewables is emerging as a promising opportunity.

Built on six acres, the one-megawatt generator and its 3,500 solar panels will produce power to be sold into the province’s electrical grid, providing annual revenues for the band of $80,000 to $150,000, depending on energy demand and pricing.

The project cost $2.7 million, including connection costs and background studies, said Sam Minde, chief executive officer of the band-owned Neyaskweyahk Group of Companies Inc.

It was paid for with grants from the Western Economic Diversification Fund and the province’s Climate Leadership Plan, and, amid Ottawa’s green electricity contracting push, is expected to be connected to the grid by mid-December.

“It’s going to be the biggest distributed generation in Alberta,” he said.

Called the Sundancer generator, it was built and will be operated through a partnership with SkyFire Energy, reflecting how renewable power developers design better projects by combining diverse resources.

Minde said the project’s benefits extend beyond Ermineskin First Nation, one of four First Nations at Maskwacis, 20 km north of Ponoka, in a province where renewable energy surge could power thousands of jobs.

“Our nation is looking to do the best it can in business. It’s competitive, but at the same time, what is good for us is good for the region.

“If we’re creating jobs, we’re going to be building up our economy. And if you look at our region right now, we need to continue to create opportunities and jobs.”

Electricity prices are rock bottom right now, in the six to nine cents per kilowatt hour range, with recent Alberta solar contracts coming in below natural gas on cost. During the oilsands boom, when power demand was skyrocketing, the price was in the 16 to 18 cent range.

That means there is a lot of room for bigger returns for Ermineskin in the future, especially if pipelines such as TransMountain get going or the oilsands pick up again, and as Alberta solar growth accelerates in the years ahead.

The band is so confident that Sundancer will prove a success that there are plans to double it in size, a strategy echoed by community-scale efforts such as the Summerside solar project that demonstrate scalability. By next summer, a $1.5-million to $1.7-million project funded by the band will be built on another six acres nearby.

Minde said the project is an example of the community’s connection with the environment being used to create opportunities and embracing technologies that will likely figure large in the world’s energy future.

 

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Putting Africa on the path to universal electricity access

West and Central Africa Electricity Access hinges on utility reform, renewable energy, off-grid solar, mini-grids, battery storage, and regional grid integration, lowering costs, curbing energy poverty, and advancing SDG7 with sustainable, reliable power solutions.

 

Key Points

Expanding reliable power via renewables, grid trade, and off-grid systems to cut energy poverty and unlock inclusive growth.

✅ Utility reform lowers costs and improves service reliability

✅ Regional grid integration enables clean, least-cost power trade

✅ Off-grid solar and mini-grids electrify remote communities

 

As commodity prices soar and leaders around the world worry about energy shortages and prices of gasoline at the pump, millions of people in Africa still lack access to electricity.  One-half of the people on the continent cannot turn on a fan when temperatures go up, can’t keep food cool, or simply turn the lights on. This energy access crisis must be addressed urgently.

In West and Central Africa, only three countries are on track to give every one of their people access to electricity by 2030. At this slow pace, 263 million people in the region will be left without electricity in ten years.  West Africa has one of the lowest rates of electricity access in the world; only about 42% of the total population, and 8% of rural residents, have access to electricity.

These numbers, some far too big, others far too small, have grave consequences. Electricity is an important step toward enhancing people’s opportunities and choices. Access is key to boosting economic activity and contributes to improving human capital, which, in turn, is an investment in a country’s potential.  

Without electricity, children can’t do their schoolwork at night. Businesspeople can’t get information on markets or trade with each other. Worse, as the COVID-19 pandemic has shown so starkly, limited access to energy constrains hospital and emergency services, further endangering patients and spoiling precious medicine.  

What will it take to power West and Central Africa?  
As the African continent recovers from COVID-19 impacts, now is the critical time to accelerate progress towards universal energy access to drive the region’s economic transformation, promote socio-economic inclusion, and unlock human capital growth. Without reliable access to electricity, the holes in a country’s social fabric can grow bigger, those without access growing disenchanted with inequality.  

Tackling the Africa region’s energy access crisis requires four bold approaches. 

First, this involves making utilities financially viable. Many power providers in the region are cash-strapped, operate dilapidated and aging generation fleet and infrastructure. Therefore, they can’t deliver reliable and affordable electricity to their customers, let alone deliver electricity to those that currently must rely on inadequate alternatives to electricity. Overall, fewer than half of the utilities in Sub-Saharan Africa recover their operating costs, resulting in GDP losses as high as four percent in some countries.

Improving the performance of national utilities and greening their power generation mix is a prerequisite to lowering the costs of supply, thus expanding electricity access to those currently unelectrified, usually lower-income and often remote households. 

In that effort — and this a critical second point — West and Central African countries need to look beyond their borders and further integrate their national utilities and grids to other systems in the region. The region has an abundance of affordable clean energy sources — hydropower in Guinea, Mali, and Cote d’Ivoire; high solar irradiation in the Sahel — but the regional energy market is fragmented. 

Without efficient regional trade, many countries are highly dependent on one or two energy resources and heavily reliant on inefficient, polluting generation sources, requiring fuel imports linked to volatile international oil prices.

The vision of an integrated regional power market in countries of the Economic Community of West African States (ECOWAS) is coming a step closer to reality thanks to an ambitious program of cross-border interconnection projects. If countries take full advantage of this grid, the share of the region’s electricity consumption traded across borders would more than double from 8 percent today to about 17 percent by 2030. Overall, regional power trade could lower the lifecycle cost of West Africa’s power generation system by about 10 percent and provide greener energy by 2030. 

Third, electrification efforts need to be open to private sector investments and innovations, such as renewables like solar energy and battery storage, which have made a tremendous impact in enabling access for millions of poor and underserved households.  Specifically, off-grid solar systems and mini-grids have become a proven reliable way to provide affordable modern electricity services, powering homes in rural communities, healthcare facilities, and schools.

Burkina Faso, which enjoys one of the best solar radiation conditions in the region, is a successful example of leveraging the transformative impact of solar energy and battery storage. With support from the World Bank, the country is deploying solar energy to power its national grid, as well as mini-grids and individual household systems. Solar power with battery storage is competitive in Burkina Faso compared to other technologies and its government was successful in attracting private sector investments to support this technology.

Last, achieving universal electricity access will involve significant commitment from political leaders, especially developing policies and regulations that can attract high-quality investments.  

A significant step in that direction was achieved at the World Bank’s 2020 Annual Meetings with a commitment to set up the Powering Transformation Platform in each African country. Through the platform, each government will set their country-specific vision, goals and metrics, track progress, and explore and exchange innovative ideas and emerging best practices according to their own national energy needs and plans. 

This platform will bring together the elements needed to bring electricity to all in West and Central Africa and help attract new financing.

Over the last 3 years, the World Bank has doubled its investments to increase electricity access rates in Central and West Africa.  We have committed more than $7.8 billion to support 40 electricity access programs, of which more than half directly support new electricity connections. These operations are expected to provide access to 16 million people. The aim is to increase electricity access rates in West and Central Africa from 50 percent today to 64 percent by 2026.

However, World Bank’s financing alone is not enough. Our estimates show that nearly $20 billion are required for universal electrification across Sub-Saharan Africa, aligning with calls to quadruple power investment to meet demand, with about $10 billion annually needed for West and Central Africa. 

Closing the funding gap will require mobilizing traditional and new partners, especially the private sector, which is willing to invest if enabling conditions are in place, as well as philanthropic capital, that can fill in the space in areas not yet commercially attractive. The World Bank is ready to play a catalytical role in leveraging new investments. 

This is vital as less than a decade remains to reach the 2030 SDG7 goal of ensuring electricity for all through affordable, reliable, and modern energy services. As headlines worldwide focus on soaring energy prices in the developed world, we cannot lose sight of the vast populations in Africa that still cannot access basic energy services. This is the true global energy crisis.  

 

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