Construction of floating power station on hold

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The construction of Russia's first floating nuclear power plant, Academiciam Lomonosov, has been put on hold because the Sevmash factory, its main contractor, is facing budget shortfalls.

The company is a Defense Ministry factory whose priority is fulfilling military orders.

In May, Russian officials announced that the delay in the building of the floating nuclear power plant would not last more than five months, adding that the plant would be ready in 2011 instead of the originally estimated date of 2010.

The controversial power station is equipped with two 30-MW KLT40C reactors housed in ice-breaking vessels. The construction, which is estimated at more than $336 million, is 60% complete.

The floating nuclear power plant will supply electricity to the town of Severodvinsk and will cover the nearby Sevmash shipbuilding plant's energy needs.

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PG&E's bankruptcy plan wins support from wildfire victims

PG&E Bankruptcy Plan outlines wildfire victims compensation via a $13.5B trust funded by cash and stock, aiming CPUC and court approval before June 30 to access the state wildfire insurance fund and finalize settlement.

 

Key Points

A regulator-approved plan funding a $13.5B wildfire victims trust with cash and PG&E stock to exit bankruptcy.

✅ $13.5B trust split between cash and PG&E shares

✅ Targets CPUC and court approval to meet June 30 deadline

✅ Accesses state wildfire insurance fund for future risks

 

Pacific Gas & Electric's plan for getting out of bankruptcy has won overwhelming support from the victims of deadly Northern California wildfires ignited by the utility's fraying electrical grid, while some have pursued mega-fire lawsuits through the courts as well, despite concerns that they will be shortchanged by a $13.5 billion fund that's supposed to cover their losses.

The company announced the preliminary results of the vote on Monday without providing a specific tally. Those numbers are supposed to be filed with U.S. Bankruptcy Judge Dennis Montali by Friday.

The backing of the wildfire victims keeps PG&E on track to meet a June 30 deadline to emerge from bankruptcy in time to qualify for a coverage from a California wildfire insurance fund created to help protect the utility from getting into financial trouble again.

The current bankruptcy case, which began early last year, will require PG&E to pay out about $25.5 billion to cover the devastation caused by its neglect, including a Camp Fire guilty plea that underscored liabilities in court proceedings. It's the second time in less than 20 years that PG&E has filed for bankruptcy.

The backing for PG&E's plan isn't a surprise, even though some of the roughly 80,000 wildfire victims had been trying to rally resistance to what they consider to be a deeply flawed plan. The misgivings mostly center on the massive debt that the utility will take on to finance the plan and uncertainties about the fluctuating value of the $6.75 billion in company stock that comprises half of the $13.5 billion promised them.

As it became apparent that the COVID-19 pandemic would drive the economy into a deep recession, PG&E's shares plunged along with the rest of the stock market during March, even as it announced pandemic response measures for customers and employees during that period. That led one financial expert to estimate the PG&E stock earmarked for the wildfire victims' trust would be worth only $4.85 billion, a nearly 30% markdown.

But PG&E's stock price has rebounded in recent weeks and it's now worth more than it was when the deal setting up the victims' trust was struck last December. The shares surged more than 8% to $12.28 in Monday's late afternoon trading. The stock stood at $9.65 when PG&E reached its settlement the wildfire victims.

Critics of the utility's plan also are upset because the company still hasn't specified when the fire victims will be able to sell the shares. It now seems likely the victims will have to hold the stock through the upcoming wildfire season in Northern California, raising the specter that another calamity caused by the utility's badly outdated equipment, as power line fire reports have underscored, could cause the shares to plummet before they can cash out.

A petition signed by more than 3,100 wildfire victims recently urged Gov. Gavin Newsom to consider pushing back the deadline for qualifying for the state's wildfire from June 30 to late August to allow for more time to revise PG&E's plan, as many also turn to a wildfire assistance program for interim aid while they wait. Newsom's office hasn't responded to inquiry about the plan from The Associated Press.

But the lawyers representing the wildfire victims advised their clients to vote in favor of PG&E's plan, contending that it's the best deal they are going to get.

PG&E still must get its plan approved by the judge supervising its case, and a recent judge order on dividend use underscores the focus on wildfire mitigation. The confirmation hearings are scheduled to begin May 27. The judge, though, has indicated he will give great weight to the wishes of the wildfire victims.

California state regulators also must approve PG&E's plan, amid projections that rates will stabilize in 2025 for customers. A vote on that is scheduled Thursday before the Public Utilities Commission.

 

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Price Spikes in Ireland Fuel Concerns Over Dispatachable Power Shortages in Europe

ISEM Price Volatility reflects Ireland-Northern Ireland grid balancing pressures, driven by dispatchable power shortages, day-ahead market dynamics, renewable shortfalls, and interconnector constraints, affecting intraday trading, operational reserves, and cross-border electricity flows.

 

Key Points

ISEM price volatility is Irish power price swings from grid balancing stress and limited dispatchable capacity.

✅ One-off spike linked to plant outage and low renewables

✅ Day-ahead market settling; intraday trading integration pending

✅ Interconnectors and reserves vital to manage adequacy

 

Irish grid-balancing prices soared to €3,774 ($4,284) per megawatt-hour last month amid growing concerns over dispatchable power capacity across Europe.

The price spike, triggered by an alert regarding generation losses, came only four months after Ireland and Northern Ireland launched an Integrated Single Electricity Market (ISEM) designed to make trading more competitive and improve power distribution across the island.

Evie Doherty, senior consultant for Ireland at Cornwall Insight, a U.K.-based energy consultancy, said significant price volatility was to be expected while ISEM is still settling down, aligning with broader 2019 grid edge trends seen across markets.

When the U.K. introduced a single market for Great Britain, called British Electricity Trading and Transmission Arrangements, in 2005, it took at least six months for volatility to subside, Doherty said.

In the case of ISEM, “it will take more time to ascertain the exact drivers behind the high prices,” she said. “We are being told that the day-ahead market is functioning as expected, but it will take time to really be able to draw conclusions on efficiency.”

Ireland and Northern Ireland have been operating with a single market “very successfully” since 2007, said Doherty. Although each jurisdiction has its own regulatory authority, they make joint decisions regarding the single market.

ISEM, launched in October 2018, was designed to help include Ireland and Northern Ireland day-ahead electricity prices in a market pricing system called the European Union Pan-European Hybrid Electricity Market Integration Algorithm.

In time, ISEM should also allow the Irish grids to participate in European intraday markets, and recent examples like Ukraine's grid connection underline the pace of integration efforts across Europe. At present, they are only able to do so with Great Britain. “The idea was to...integrate energy use and create more efficient flows between jurisdictions,” Doherty said.

EirGrid, the Irish transmission system operator, has reported that flows on its interconnector with Northern Ireland are more efficient than before, she said.

The price spike happened when the System Operator for Northern Ireland issued an alert for an unplanned plant outage at a time of low renewable output and constraints on the north-south tie-line with Ireland, according to a Cornwall Insight analysis.

 

Not an isolated event

Although it appears to have been a one-off event, there are increasing worries that a shortage of dispatchable power could lead to similar situations elsewhere across Europe, as seen in Nordic grid constraints recently.

Last month, newspaper Frankfurter Allgemeine Zeitung (FAZ) reported that German industrial concerns had been forced to curtail more than a gigawatt of power consumption to maintain operational reserves on the grid in December, after renewable production fell short of expectations and harsh weather impacts strained systems elsewhere.

Paul-Frederik Bach, a Danish energy consultant, has collected data showing that this was not an isolated incident. The FAZ report said German aluminum smelters had been forced to cut back on energy use 78 times in 2018, he noted.

Energy availability was also a concern last year in Belgium, where six out of seven nuclear reactors had been closed for maintenance. The closures forced Belgium to import 23 percent of its electricity from neighboring countries, Bach reported.

In a separate note, Bach revealed that 11 European countries that were net importers of energy had boosted their imports by 26 percent between 2017 and 2018. It is important to note that electricity imports do not necessarily imply a shortage of power, he stated.

However, it is also true that many European grid operators are girding themselves for a future in which dispatchable power is scarcer than today.

EirGrid, for example, expects dispatchable generation and interconnection capacity to drop from 10.6 gigawatts in 2018 to 9 gigawatts in 2027.

The Swedish transmission system operator Svenska Kraftnät, meanwhile, is forecasting winter peak power deficits could rise from 400 megawatts currently to 2.5 gigawatts in 2020-21.

Research conducted by the European Network of Transmission System Operators for Electricity, suggests power adequacy will fall across most of Europe up to 2025, although perhaps not to a critical degree.

The continent’s ability to deal with the problem will be helped by having more efficient trading systems, Bach told GTM. That means developments such as ISEM could be a step in the right direction, despite initial price volatility.

In the long run, however, Europe will need to make sure market improvements are accompanied by investments in HVDC technology and interconnectors and reserve capacity. “Somewhere there must be a production of electricity, even when there is no wind,” said Bach. 

 

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Canada Extends Net-Zero Target to 2050

Canada Clean Electricity Regulations 2050 balance net-zero goals with grid reliability and affordability, setting emissions caps, enabling offset credits, and flexible provincial pathways, including support for non-grid facilities during the clean energy transition.

 

Key Points

A federal plan for a net-zero grid by 2050 with emissions caps, offsets, and flexible provincial compliance.

✅ Emissions cap targeting 181 Mt CO2 from the power sector by 2050

✅ Offset credits and annual limits enable compliance flexibility

✅ Support for remote, non-grid facilities and regional pathways

 

In December 2024, the Government of Canada announced a significant policy shift regarding its clean electricity objectives. The initial target to achieve a net-zero electricity grid by 2035 has been extended to 2050. This decision reflects the government's response to feedback from provinces and energy industry stakeholders, who expressed concerns about the feasibility of meeting the 2035 deadline.

Revised Clean Electricity Regulations

The newly finalized Clean Electricity Regulations (CER) outline the framework for Canada's transition to a net-zero electricity grid by 2050, advancing the goal of 100 per cent clean electricity nationwide.

  • Emissions Reduction Targets: The regulations set a cap on emissions from the electricity sector, targeting a reduction of 181 megatonnes of CO₂ by 2050. This is a decrease from the previous goal of 342 megatonnes, reflecting a more gradual approach to emissions reduction.

  • Flexibility Mechanisms: To accommodate the diverse energy landscapes across provinces, the CER introduces flexibility measures. These include annual emissions limits and the option to use offset credits, allowing provinces to tailor their strategies while adhering to national objectives.

  • Support for Non-Grid Connected Facilities: Recognizing the unique challenges of remote and off-grid communities, the regulations provide accommodations for certain non-grid connected facilities, ensuring that all regions can contribute to the national clean electricity goals.

Implications for Canada's Energy Landscape

The extension of the net-zero electricity target to 2050 signifies a strategic recalibration of Canada's energy policy. This adjustment acknowledges the complexities involved in transitioning to a clean energy future, including:

  • Grid Modernization: Upgrading the electrical grid to accommodate renewable energy sources and ensure reliability is a critical component of the transition, especially as Ontario's EV wave accelerates across the province.

  • Economic Considerations: Balancing environmental objectives with economic impacts is essential. The government aims to create over 400,000 clean energy jobs, fostering economic growth while reducing emissions, supported by ambitious EV goals in the transport sector.

  • Regional Variations: Provinces have diverse energy profiles and resources, and British Columbia's power supply challenges highlight planning constraints. The CER's flexibility mechanisms are designed to accommodate these differences, allowing for tailored approaches that respect regional contexts.

Public and Industry Reactions

The policy shift has elicited varied responses:

  • Environmental Advocates: Some environmental groups express concern that the extended timeline may delay critical climate action, while debates over Quebec's push for EV dominance underscore policy trade-offs. They emphasize the need for more ambitious targets to address the escalating impacts of climate change.

  • Industry Stakeholders: The energy sector generally welcomes the extended timeline, viewing it as a pragmatic approach that allows for a more measured transition, particularly amid criticism of the 2035 EV mandate in transportation policy. The flexibility provisions are particularly appreciated, as they provide the necessary leeway to adapt to evolving market and technological conditions.

Looking Forward

As Canada moves forward with the implementation of the Clean Electricity Regulations, the focus will be on:

  • Monitoring Progress: Establishing robust mechanisms to track emissions reductions and ensure compliance with the new targets.

  • Stakeholder Engagement: Continuing dialogue with provinces, industry, and communities to refine strategies and address emerging challenges, including coordination on EV sales regulations as complementary measures.

  • Innovation and Investment: Encouraging the development and deployment of clean energy technologies through incentives and support programs.

The extension of Canada's net-zero electricity target to 2050 represents a strategic adjustment aimed at achieving a balance between environmental goals and practical implementation considerations. The Clean Electricity Regulations provide a framework that accommodates regional differences and industry concerns, setting the stage for a sustainable and economically viable energy future.

 

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Greening Ontario's electricity grid would cost $400 billion: report

Ontario Electricity Grid Decarbonization outlines the IESO's net-zero pathway: $400B investment, nuclear expansion, renewables, hydrogen, storage, and demand management to double capacity by 2050 while initiating a 2027 natural gas moratorium.

 

Key Points

A 2050 plan to double capacity, retire gas, and invest $400B in nuclear, renewables, and storage for a net-zero grid.

✅ $400B over 25 years to meet net-zero electricity by 2050

✅ Capacity doubles to 88,000 MW; demand grows ~2% annually

✅ 2027 gas moratorium; build nuclear, renewables, storage

 

Ontario will need to spend $400 billion over the next 25 years in order to decarbonize the electricity grid and embrace clean power according to a new report by the province’s electricity system manager that’s now being considered by the Ford government.

The Independent System Electricity Operator (IESO) was tasked with laying out a path to reducing Ontario’s reliance on natural gas for electricity generation and what it would take to decarbonize the entire electricity grid by 2050.

Meeting the goal, the IESO concluded, will require an “aggressive” approach of doubling the electricity capacity in Ontario over the next two-and-a-half decades — from 42,000 MW to 88,000 MW — by investing in nuclear, hydrogen and wind and solar power while implementing conservation policies and managing demand.

“The process of fully eliminating emissions from the grid itself will be a significant and complex undertaking,” IESO president Lesley Gallinger said in a news release.

The road to decarbonization, the IESO said, begins with a moratorium on natural gas power generation starting in 2027 as long as the province has “sufficient, non-emitting supply” to meet the growing demands on the grid.

The approach, however, comes with significant risks.

The IESO said hydroelectric and nuclear facilities can take 10 to 15 years to build and if costs aren’t controlled the plan could drive up the price of clean electricity, turning homeowners and businesses away from electrification.

“Rapidly rising electricity costs could discourage electrification, stifle economic growth or hurt consumers with low incomes,” the report states.

The IESO said the province will need to take several “no regret” actions, including selecting sites and planning to construct new large-scale nuclear plants as well as hydroelectric and energy storage projects and expanding energy-efficiency programs beyond 2024.

READ MORE: Ontario faces calls to dramatically increase energy efficiency rebate programs

Ontario’s minister of energy didn’t immediately commit to implementing the recommendations, citing the need to consult with stakeholders first.

“I look forward to launching a consultation in the new year on next steps from today’s report, including the potential development of major nuclear, hydroelectric and transmissions projects,” Todd Smith said in a statement.

Currently, electricity demand is increasing by roughly two per cent per year, raising concerns Ontario could be short of electricity in the coming years as the manufacturing and transportation sectors electrify and as more sectors consider decarbonization.

At the same time, the province’s energy supply is facing “downward pressure” with the Pickering nuclear power plant slated to wind down operations and the Darlington nuclear generating station under active refurbishment.

To meet the energy need, the Ford government said it intended to extend the life of the Pickering plant until 2026.

READ MORE: Ontario planning to keep Pickering nuclear power station open until 2026

But to prepare for the increase, the Ontario government was told the province would also need to build new natural gas facilities to bridge Ontario’s electricity supply gap in the near term — a recommendation the Ford government agreed to.

The IESO said a request for proposals has been opened and the province is looking for host communities, with the expectation that existing facilities would be upgraded before projects on undeveloped land would be considered.

The IESO said the contract for any new facilities would expire in 2040, and all natural gas facilities would be retired in the 2040s.

 

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Electricity Shut-Offs in a Pandemic: How COVID-19 Leads to Energy Insecurity, Burdensome Bills

COVID-19 Energy Burden drives higher electricity bills as income falls, intensifying energy poverty, utility shut-offs, and affordability risks for low-income households; policy moratoriums, bill relief, and efficiency upgrades are vital responses.

 

Key Points

The COVID-19 energy burden is the rising share of income spent on energy as bills increase and earnings decline.

✅ Rising home demand and lost wages increase energy cost share.

✅ Mandated shut-off moratoriums and reconnections protect health.

✅ Fund assistance, efficiency, and solar for LMI households.

 

I have asthma. It’s a private piece of medical information that I don’t normally share with people, but it makes the potential risks associated with exposure to the coronavirus all the more dangerous for me. But I’m not alone. 107 million people in the U.S. have pre-existing medical conditions like asthma and heart disease; the same pre-existing conditions that elevate their risk of facing a life-threatening situation were we to contract COVID-19. There are, however, tens of millions more house-bound Americans with a condition that is likely to be exacerbated by COVID-19: The energy burden.

The energy burden is a different kind of pre-existing condition:
In the last four weeks, 22 million people filed for unemployment. Millions of people will not have steady income (or the healthcare tied to it) to pay rent and utility bills for the foreseeable future which means that thousands, possibly millions of home-bound Americans will struggle to pay for energy.

Your energy burden is the amount of your monthly income that goes to paying for energy, like your monthly electric bill. So, when household energy use increases or income decreases, your energy burden rises. The energy burden is not a symptom of the pandemic and the economic downturn; it is more like a pre-existing condition for many Americans.

Before the coronavirus outbreak, I shared a few maps that showed how expensive electricity is for some. The energy burden in most pronounced in places already struggling economically, like in Appalachia, where residents in some counties must put more than 30 percent of their income toward their electric bills, and in the Midwest where states such as Michigan have some families spending more than 1/5 of their income on energy bills. The tragic facts are that US families living below the poverty line are far more likely to also be suffering from their energy burden.

But like other pre-existing conditions, the impacts of the coronavirus pandemic are exacerbating the underlying problems afflicting communities across the country.

Critical responses to minimize the spread of COVID-19 are social distancing, washing hands frequently, covering our faces with masks and staying at home. More time at home for most will drive up energy bills, and not by a little. Estimates on how much electricity demand during COVID-19 will increase vary but I’ve seen estimates as high as a 20% increase on average. For some families that’s a bag of groceries or a refill on prescription medication.

What happens when the power gets turned off?
Under normal conditions, if you cannot pay your electric bill your electricity can get turned off. This can have devastating consequences. Most states have protections for health and medical reasons and some states have protections during extreme heat or cold weather. But enforcement of those protections can vary by utility service area and place unnecessary burdens on the customer.

UCS
Only Florida has no protections of any kind against utility shut-offs when health or medical reasons would merit protection against it. However, when it comes to protection against extreme heat, only a few states have mandatory protections based on temperature thresholds.

The NAACP has also pointed out that utilities have unceremoniously disconnected the power of millions of people, disproportionally African-American and Latinx households.

April tends to be a mild month for most of the country, but the South already had its first heat wave at the end of March. If this pandemic lasts into the summer, utility disconnects could become deadly, and efforts to prevent summer power outages will be even more critical to public health. In the summer, during extreme summer heat families can’t turn off the A/C and go to the movies if we are following public health measures and sheltering in place. Lots of families that don’t have or can’t afford to run A/C would otherwise gather at local community pools, beaches, or in cooling centers, but with parks, pools and community groups closed to prevent the virus’s spread, what will happen to these families in July or August?

But we won’t have to wait till the summer to see how families will be hard hit by falling behind on bills and losing power. Here are a few ways electricity disconnection policies cause people harm during the pandemic:

Loss of electricity during the COVID-19 pandemic means families will lose their ability to refrigerate essential food supplies.
Child abuse guidance discusses how unsanitary household conditions are a contributing factor to child protective services involvement. Unsanitary household conditions can include, for example, rotting food (which might happen if electricity is cut off).

HUD’s handbook on federally subsidized housing includes a chapter on termination, which says that lease agreements can be terminated for repeated minor infractions including failing to pay utilities.
Airway machines used to treat respiratory ailments—pre-existing conditions in this pandemic—will not work. Our elderly neighbors in particular might rely on medicine that requires refrigeration or medical equipment that requires electricity. They too have fallen victim to utility shut-offs even during the pandemic.

Empowering solutions are available today

Decisionmakers seeking solutions can look to implement utility shut off moratoriums as a good start. Good news is that many utilities have voluntarily taken action to that effect, and New Jersey and New York have suspended shut-offs, one of the best trackers on who is taking what action has been assembled by Energy Policy Institute.

But voluntary actions do not always provide comprehensive protection, and they certainly have not been universally adopted across the country. Some utilities are waiving fees as relief measures, and some moratoriums only apply to customers directly affected by COVID-19, which will place additional onerous red tape on households that are stricken and perhaps unable to access testing. Others might only be an extension of standard medical shut off protections. Moratoriums put in place by voluntary action can also be revoked or lifted by voluntary action, which does not provide any sense of certainty to people struggling to make ends meet.

This is why the US needs mandatory moratoriums on all utility disconnections. These normally would be rendered at the state level, either by a regulatory commission, legislative act, or even an emergency executive order. But the inconsistent leadership among states in response to the COVID-19 crisis suggests that Congressional action is needed to ensure that all vulnerable utility customers are protected. That’s exactly what a coalition of organizations, including UCS, is calling for in future federal aid legislation. UCS has called for a national moratorium on utility shut-offs.

And let’s be clear, preventing new shut-offs isn’t enough. Cutting power off at residence during a pandemic is not good public policy. People who are without electricity should have it restored so residents can safely shelter in place and help flatten the curve. So far, only Colorado and Wisconsin’s leadership has taken this option.

Addressing the root causes of energy poverty
Preventing shut-offs is a good first step, but the increased bill charges will nevertheless place greater economic pressure on an incalculable number of families. Addressing the root of the problem (energy affordability) must be prioritized when we begin to recover from the health and economic ramifications of the COVID-19 pandemic.

One way policymakers can do that is to forgive outstanding balances on utility bills, perhaps with an eligibility cap based on income. Additional funds could be made available to those who are still struggling to pay their bills via capping bills, waiving late payment fees, automating payment plans or other protective measures that rightfully place consumers (particularly vulnerable consumers) at the center of any energy-related COVID-19 response. Low-and-moderate-income energy efficiency and solar programs should be funded as much as practically possible.

New infrastructure, particularly new construction that is slated for public housing, subsidized housing, or housing specifically marketed for low- and moderate-income families, should include smart thermostats, better insulation, and energy-efficient appliances.

Implementing these solutions may seem daunting, let us not forget that one of the best ways to ease people’s energy burden is to keep a utility’s overall energy costs low. That means state utility commissions must be vigilant in utility rate cases and fuel recovery cost dockets to protect people facing unfathomable economic pressures. Unscrupulous utilities have been known to hide unnecessary costs in our energy bills. Commissions and their staff are overwhelmed at this time, but they should be applying extra scrutiny during proceedings when utilities are recovering costs associated with delivering energy.

What might a utility try to get past the commission?
Well, residential demand is up, so for many people, bills will increase. However, wholesale electricity rates are low right now, in some cases at all-time lows. Why? Because industrial and commercial demand reductions (from social distancing at home) have more than offset residential demand increases. Overall US electricity demand is flat or declining, and supply/demand economics predicts that when demand decreases, prices decrease.

At the same time, natural gas prices have set record lows each month of this year and that’s a trend that is expected to hold true for a while.

Low demand plus low gas prices mean wholesale market prices are incredibly low. Utilities should be taking advantage of low market prices to ensure that they deliver electricity to customers at as low a cost as possible. Utilities must also NOT over-run coal plants uneconomically or lean on aging capacity despite disruptions in coal and nuclear that can invite brownouts because that will not only needlessly cost customers more, but it will also increase air pollution which will exacerbate respiratory issues and susceptibility to COVID-19, according to a recent study published by Harvard.

 

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Project examines potential for Europe's power grid to increase HVDC Technology

HVDC-WISE Project accelerates HVDC technology integration across the European transmission system, delivering a planning toolkit to boost grid reliability, resilience, and interconnectors for renewables and offshore wind amid climate, cyber, and physical threats.

 

Key Points

EU-funded project delivering tools to integrate HVDC into Europe's grid, improving reliability, resilience, and security.

✅ EU Horizon Europe-backed consortium of 14 partners

✅ Toolkit to assess extreme events and grid operability

✅ Supports interconnectors, offshore wind, and renewables

 

A partnership of 14 leading European energy industry companies, research organizations and universities has launched a new project to identify opportunities to increase integration of HVDC technology into the European transmission system, echoing calls to invest in smarter electricity infrastructure from abroad.

The HVDC-WISE project, in which the University of Strathclyde is the UK’s only academic partner, is supported by the European Union’s Horizon Europe programme.

The project’s goal is to develop a toolkit for grid developers to evaluate the grid’s performance under extreme conditions and to plan systems, leveraging a digital grid approach that supports coordination to realise the full range of potential benefits from deep integration of HVDC technology into the European transmission system.

The project is focused on enhancing electric grid reliability and resilience while navigating the energy transition. Building and maintaining network infrastructure to move power across Europe is an urgent and complex task, and reducing losses with superconducting cables can play a role, particularly with the continuing growth of wind and solar generation. At the same time, threats to the integrity of the power system are on the rise from multiple sources, including climate, cyber, and physical hazards.

 

Mutual support

At a time of increasing worries about energy security and as Europe’s electricity systems decarbonise, connections between them to provide mutual support and routes to market for energy from renewables, a dynamic also highlighted in discussions of the western Canadian electricity grid in North America, become ever more important.

In modern power systems, this means making use of High Voltage Direct Current (HVDC) technology.

The earliest forms of technology have been around since the 1960s, but the impact of increasing reliance on HVDC and its ability to enhance a power system’s operability and resilience are not yet fully understood.

Professor Keith Bell, Scottish Power Professor of Future Power Systems at the University of Strathclyde, said:

As an island, HVDC is the only practical way for us to build connections to other countries’ electricity systems. We’re also making use of it within our system, with one existing and more planned Scotland-England subsea link projects connecting one part of Britain to another.

“These links allow us to maximise our use of wind energy. New links to other countries will also help us when it’s not windy and, together with assets like the 2GW substation now in service, to recover from any major disturbances that might occur.

“The system is always vulnerable to weather and things like lightning strikes or short circuits caused by high winds. As dependency on electricity increases, insights from electricity prediction specialists can inform planning as we enhance the resilience of the system.”

Dr Agusti Egea-Alvarez, Senior Lecturer at Strathclyde, said: “HVDC systems are becoming the backbone of the British and European electric power network, either interconnecting countries, or connecting offshore wind farms.

“The tools, procedures and guides that will be developed during HVDC-WISE will define the security, resilience and reliability standards of the electric network for the upcoming decades in Europe.”

Other project participants include Scottish Hydro Electric Transmission, the Supergrid Institute, the Electric Power Research Institute (EPRI) Europe, Tennet TSO, Universidad Pontificia Comillas, TU Delft, Tractebel Impact and the University of Cyprus.

 

Climate change

Eamonn Lannoye, Managing Director of EPRI Europe, said: “The European electricity grid is remarkably reliable by any standard. But as the climate changes and the grid becomes exposed to more extreme conditions, energy interdependence between regions intensifies and threats from external actors emerge. The new grid needs to be robust to those challenges.”

Juan Carlos Gonzalez, a senior researcher with the SuperGrid Institute which leads the project said: “The HVDC-WISE project is intended to provide planners with the tools and know-how to understand how grid development options perform in the context of changing threats and to ensure reliability.”

HVDC-WISE is supported by the European Union’s Horizon Europe programme under agreement 101075424 and by the UK Research and Innovation Horizon Europe Guarantee scheme.

 

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