Contractor counters Atlas suit

European Grid Frequency Clock Slowdown has made appliance clocks run minutes behind as AC frequency drifts on the 50 Hz electricity grid, driven by a Kosovo-Serbia billing dispute and ENTSO-E monitored supply-demand imbalance.

Key Points

An EU-wide timing error where 50 Hz AC deviations slow appliance clocks due to Kosovo-Serbia grid imbalances.

✅ Clocks drifted up to six minutes across interconnected Europe

✅ Cause: unpaid power in N. Kosovo, contested by Serbia

✅ ENTSO-E reported 50 Hz deviations from supply-demand mismatch

Over the past couple of months, Europeans have noticed time slipping away from them. It’s not just their imaginations: all across the continent, clocks built into home appliances like ovens, microwaves, and coffee makers have been running up to six minutes slow. The unlikely cause? A dispute between Kosovo and Serbia over who pays the electricity bill.

To make sense of all this, you need to know that the clocks in many household devices use the frequency of electricity to keep time. Electric power is delivered to our homes in the form of an alternating current, where the direction of the flow of electricity switches back and forth many times a second. (How this system came to be established is complex, but the advantage is that it allows electricity to be transmitted efficiently.) In Europe, this frequency is 50 Hertz — meaning a current alternating of 50 times a second. In America, it’s 60 Hz, and during peak summer demand utilities often prepare for blackouts as heat drives loads higher.

Since the 1930s, manufacturers have taken advantage of this feature to keep time. Each clock needs a metronome — something with a consistent rhythm that helps space out each second — and an alternating current provides one, saving the cost of extra components. Customers simply set the time on their oven or microwave once, and the frequency keeps it precise.

At least, that’s the theory. But because this timekeeping method is reliant on electrical frequency, when the frequency changes, so do the clocks. That is what has been happening in Europe.

The news was announced this week by ENTSO-E, the agency that oversees the single, huge electricity grid connecting 25 European countries and which recently synchronized with Ukraine to bolster regional resilience. It said that variations in the frequency of the AC caused by imbalances between supply and demand on the grid have been messing with the clocks. The imbalance is itself caused by a political argument between Serbia and Kosovo. “This is a very sensitive dispute that materializes in the energy issues,” Susanne Nies, a spokesperson for ENTSO-E, told The Verge.

Essentially, after Kosovo declared independence from Serbia in 2008, there were long negotiations over custody of utilities like telecoms and electricity infrastructure. As part of the ongoing agreements (Serbia still does not recognize Kosovo as a sovereign state), four Serb-majority districts in the north of Kosovo stopped paying for electricity. Kosovo initially covered this by charging the rest of the country more, but last December, it decided it had had enough and stopped paying. This led to an imbalance: the Kosovan districts were still using electricity, but no one was paying to put it on the grid.

This might sound weird, but it’s because electricity grids work on a system of supply and demand, where surging consumption has even triggered a Nordic grid blockade in response to constrained flows. As Stewart Larque of the UK’s National Grid explains, you want to keep the same amount of electricity going onto the grid from power stations as the amount being taken off by homes and businesses. “Think of it like driving a car up a hill at a constant speed,” Larque told The Verge. “You need to carefully balance acceleration with gravity.” (The UK itself has not been affected by these variations because it runs its own grid.)

“THEY ARE FREE-RIDING ON THE SYSTEM.”

This balancing act is hugely complex and requires constant monitoring of supply and demand and communication between electricity companies across Europe, and growing cyber risks have spurred a renewed focus on protecting the U.S. power grid among operators worldwide. The dispute between Kosovo and Serbia, though, has put this system out of whack, as the two governments have been refusing to acknowledge what the other is doing.

“The Serbians [in Kosovo] have, according to our sources, not been paying for their electricity. So they are free-riding on the system,” says Nies.

The dispute came to a temporary resolution on Tuesday, when the Kosovan government stepped up to the plate and agreed to pay a fee of €1 million for the electricity used by the Serb-majority municipalities. “It is a temporary decision but as such saves our network functionality,” said Kosovo’s prime minister Ramush Haradinaj. In the longer term, though, a new agreement will need to be reached.

There have been rumors that the increase in demand from northern Kosovo was caused by cryptocurrency miners moving into the area to take advantage of the free electricity. But according to ENTSO-E, this is not the case. “It is absolutely unrelated to cryptocurrency,” Nies told The Verge. “There’s a lot of speculation about this, and it’s absolutely unrelated.” Representatives of Serbia’s power operator, EMS, refused to answer questions on this.

For now, “Kosovo is in balance again,” says Nies. “They are producing enough [electricity] to supply the population. The next step is to take the system back to normal, which will take several weeks.” In other words, time will return to normal for Europeans — if they remember to change their clocks, even as the U.S. power grid sees more blackouts than other developed nations.

Related News

• Electricity Forum News

• Grid Technologies News

Advanced Nuclear Reactors redefine nuclear energy with SMRs, diverse fuels, passive safety, digital control rooms, and flexible heat and power, pairing veteran operator expertise with cost-efficient, carbon-free electricity for a resilient grid.

Key Points

SMR-based advanced reactors with passive cooling and digital controls deliver flexible power and process heat.

✅ Veteran operators transfer proven safety culture and risk management.

✅ SMRs, passive safety, and digital controls simplify operations.

✅ Flexible output: electricity, process heat, and grid support.

Advanced reactors will break the mold of what we think next-gen nuclear power can accomplish: some will be smaller, some will use different kinds of fuel and others will do more than just make electricity. This new technology may seem like uncharted waters, but when operators, technicians and other workers start up the first reactors of the new generation, they will bring with them years of nuclear experience to run machines that have been optimized with lessons from the current fleet.

While advanced reactors are often portrayed as the future of nuclear energy, and atomic energy is heating up across markets, its our current plants that have paved the way for these exciting innovations and which will be workhorses for years to come.

Reactor Veterans Bring Their Expertise to New Designs

Many of the workers who will operate the next generation of reactors come from a nuclear background. Even though the design of an advanced reactor may be different, the experience and instincts these operators have gained from working at the current fleet will help new plants get off to a more productive start.

They have a questioning attitude; they are always exploring what could go wrong and always understanding the notion of risk management in nuclear operations, whether its the oldest design or the newest design, said Chip Pardee, the president of Terrestrial Energy USA, who is the former chief operating officer at two nuclear utilities, Exelon Corp. and the Tennessee Valley Authority.

They have respect for the technology and a bias towards conservative decision-making.

Jhansi Kandasamy, vice president of engineering at GE Hitachi Nuclear Energy, agrees. She said that the presence of industry veterans will benefit the new modelslike the 300 megawatt boiling water reactor her company is developing.

From the beginning, a new reactor will have people who have touched it, worked on it, and experienced it, she said.

Theyre going to be able to tell you if something doesnt look right, because theyve lived through it.

Experience Informs New Reactor Design

Advanced reactors are designed by engineers who are fully familiar with existing plants and can use that experience to optimize the new ones, like a family building a house and wanting the kitchen just so. New reactors will be simpler to operate because of insights gained from years of operations of the current fleet, and some designs even integrate molten salt energy storage to enhance flexibility.

NuScale Power LLC, for example, has a very different design from the current fleet amid an advanced nuclear push that is reshaping development: up to 12 small reactorsinstead of one or two large reactorsmanaged from a single digital control roominstead of one full of analog switches and dials. When the company designed its control room, it brought in industry veterans who had collectively worked at more than two dozen nuclear plants.

The experts that NuScale brought in critiqued everything, even down to the shape of the symbols on the computer screens to make them easier to read for operators who sometimes need to quickly interpret lots of incoming data. The control panels for NuScales small modular reactor (SMR) present information according to its importance and automatically call up appropriate procedures for operators.

Many advanced reactors are also smaller than those currently operating, which makes their components simpler and less expensive. Kandasamy pointed out that the giant mechanical pumps in todays reactors generate a lot of heat and require a lot of supporting systems, including air conditioning in the rooms that house them.

GE Hitachis SMR design relies more on passive cooling so it needs fewer pumps, and those that remain use magnets, so they generate less heat. Fewer, smaller pumps means a smaller building and less cost.

Advanced Nuclear Will Further the Work of Current Reactors

Advanced reactors promise improved flexibility and the ability to do more kinds of work, including nuclear beyond electricity applications, to displace carbon and stabilize the climate. And they will continue nuclear energys legacy of providing reliable, carbon-free electricity, as a recent new U.S. reactor startup illustrates in practice. As new designs come on line over the next decade, we will continue to rely on operating plants which provide nearly 55 percent of the countrys carbon-free electricity.

The world will need all the carbon-free generation it can get for many years to come, as companies, states and countries aim for zero emissions by mid-century and pursue strategies like the green industrial revolution to accelerate deployment. That means it will need wind, solar, advanced reactors and current plants.

Related News

• Electricity Forum News

• Power Generation News

Quebec Churchill Falls power deal renewal spotlights Hydro-Que9bec's Labrador hydroelectricity, Churchill River contract extension, Gull Island prospects, and Innu Nation rights, as demand from EV battery manufacturing and the green economy outpaces provincial supply.

Key Points

Extending Quebec's low-price Churchill Falls contract to secure Labrador hydro and address Innu Nation rights.

✅ 1969 contract delivers ~30 TWh at very low fixed price.

✅ Newfoundland seeks higher rates, equity, and consultation.

✅ Innu Nation demands benefits, consent, and land remediation.

As Quebec prepares to ramp up electricity production to meet its ambitious economic goals, the government is trying to extend a power deal that has caused decades of resentment in Newfoundland and Labrador.

Around 15 per cent of Quebec's electricity comes from the Churchill Falls dam in Labrador, through a deal set to expire in 2041 that is widely seen as unfair. Quebec Premier François Legault not only wants to extend the agreement, he wants another dam on the Churchill River and, for now, has closed the door on nuclear power as an option to help make his province what he has called a "world leader for the green economy."

But renewing that contract "won't be easy," Normand Mousseau, scientific director of the Trottier Energy Institute at Polytechnique Montréal, said in a recent interview. Extending the Churchill Falls deal is not essential to meet Quebec's energy plans, but without it, Mousseau said, "we would have some problems."

The Legault government is enticing global companies, such as manufacturers of electric vehicle batteries, to set up shop in the province and access its hydroelectricity. But demand for Quebec's power has exceeded its supply, and Ontario has chosen not to renew a power-purchase deal with Quebec, limiting the government's vision.

Last month, Quebec's hydro utility released its strategic plan calling for a production increase of 60 terawatt hours by 2035, which represents the installed capacity of three of Hydro-Québec's largest facilities. Churchill Falls produces roughly 30 terawatt hours, and Quebec would need to replace that power if it can't strike a deal to extend the contract, Mousseau said.

If Quebec wants to keep buying power from Churchill Falls, the government is going to have to pay more, said Mousseau, who is also a physics professor at Université de Montréal. "We're paying one-fifth of a cent a kilowatt hour — that's not much," he said.

Under the 1969 contract, Quebec assumed most of the financial risk of building the Churchill Falls dam in exchange for the right to buy power at a fixed price. The deal has generated more than $28 billion for Hydro-Québec; it has returned $2 billion to Newfoundland and Labrador.

That lopsided deal has stoked anti-Quebec sentiment in Newfoundland and Labrador and contributed to nationalist politics, including threats of separation from Canada around a decade and a half ago, when Danny Williams was premier, said Jerry Bannister, a history professor at Dalhousie University.

"We tend to forget what it was like during the Williams era — he hauled down the Canadian flag," Bannister said. "There was a type of angry, combative nationalism which defined energy development. And particularly Muskrat Falls, it was payback, it was revenge."

Power from the Muskrat Falls generating station, also on the Churchill River, would be sold to Nova Scotia instead of Quebec. But that project has suffered technical problems and cost overruns since, and as of June 29, the price of Muskrat Falls had reached $13.5 billion; the province had estimated the total cost would be $7.4 billion when it sanctioned the project in 2012.

Anti-Quebec feelings may have subsided, but Bannister said the Churchill Falls deal continues to influence Newfoundland politics.

In September, Premier Andrew Furey said Legault would have to show him the money(opens in a new tab) to extend th Legault's office said Tuesday that discussions are ongoing, while the Newfoundland and Labrador government said in an emailed statement Thursday that it wants to maximize the value of its "assets and future opportunities" along the Churchill River.

Whatever negotiations are happening, Grand Chief Simon Pokue of the Innu Nation of Labrador(opens in a new tab) said he has been left out of them.

Churchill Falls flooded 6,500 square kilometres of traditional Innu land, Pokue said, adding that in response, the Innu Nation filed a $4 billion lawsuit against Hydro-Québec in 2020, which is ongoing.

"A lot of damage has been done to our lands, our land is flooded and we'll never see it again," Pokue said in a recent interview. "Nobody will ever repair that."

As well, a portion of Muskrat Falls profits was supposed to go to the Innu Nation, but the cost overruns and a refinancing deal between the federal government and Newfoundland and Labrador have limited whatever money they will see.

If Legault wants another dam on the Churchill River, at Gull Island, the Innu Nation needs to be paid the kind of money it was expecting from Muskrat Falls, he said.

"You did it once, but you're not going to do it again," Pokue said. "It's not going to start until we are consulted and involved."

Meanwhile, Quebec may face competition for Churchill Falls power, Mousseau said, with at least one Labrador mining company expressing interest in buying a significant portion of its output — though he added that the dam's capacity could be increased. The low price paid by Quebec has meant there has been little incentive to upgrade the plant's turbines.

As demand for electricity rises across the country, Mousseau said he thinks it would be better for provinces to work together, sharing expertise and costs, for example through NB Power deals to import more Quebec electricity as they look across provincial borders to find the best locations for projects, rather than acting as rivals.

"We need to talk and work with other provinces, and some propose an independent planning body to guide this, but for this you need to build confidence, and there's no confidence from the Newfoundland side with respect to Quebec," he said. "So that's a challenge: how do you work on this relationship that has been broken for 50 years?"e contract, but the two premiers have said little since.

Related News

• Electricity Forum News

• Power Generation News

Lake Erie Connector Investment advances a 1,000 MW HVDC transmission link connecting Ontario to the PJM Interconnection, enhancing grid reliability, clean power trade, and GHG reductions through a public-private partnership led by CIB and ITC.

Key Points

A $1.7B public-private HVDC project linking Ontario and PJM to boost reliability, cut GHGs, and enable clean power trade.

✅ 1,000 MW, 117 km HVDC link between Ontario and PJM

✅ $655M CIB and $1.05B private financing, ITC to own-operate

✅ Cuts system costs, boosts reliability, reduces GHG emissions

The Canada Infrastructure Bank (CIB) and ITC Investment Holdings (ITC) have signed an agreement in principle to invest $1.7 billion in the Lake Erie Connector project.

Under the terms of the agreement, the CIB will invest up to $655 million or up to 40% of the project cost. ITC, a subsidiary of Fortis Inc., and private sector lenders will invest up to $1.05 billion, the balance of the project's capital cost.

The CIB and ITC Investment Holdings signed an agreement in principle to invest $1.7B in the Lake Erie Connector project.

The Lake Erie Connector is a proposed 117 kilometre underwater transmission line connecting Ontario with the PJM Interconnection, the largest electricity market in North America, and aligns with broader regional efforts such as the Maine transmission line to import Quebec hydro to strengthen cross-border interconnections.

The 1,000 megawatt, high-voltage direct current connection will help lower electricity costs for customers in Ontario and improve the reliability and security of Ontario's energy grid, complementing emerging solutions like battery storage across the province. The Lake Erie Connector will reduce greenhouse gas emissions and be a source of low-carbon electricity in the Ontario and U.S. electricity markets.

During construction, the Lake Erie Connector is expected to create 383 jobs per year and drive more than $300 million in economic activity, and complements major clean manufacturing investments like a $1.6 billion battery plant in the Niagara Region that supports the EV supply chain. Over its life, the project will provide 845 permanent jobs and economic benefits by boosting Ontario's GDP by $8.8 billion.

The project will also help Ontario to optimize its current infrastructure, avoid costs associated with existing production curtailments or shutdowns. It can leverage existing generation capacity and transmission lines to support electricity demand, alongside new resources such as the largest battery storage project planned for southwestern Ontario.

ITC continues its discussions with First Nations communities and is working towards meaningful participation in the near term and as the project moves forward to financial close.

The CIB anticipates financial close late in 2021, pending final project transmission agreements, with construction commencing soon after. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance.

ITC acquired the Lake Erie Connector project in August 2014 and it has received all necessary regulatory and permitting approvals, including a U.S. Presidential Permit and approval from the Canada Energy Regulator.

This is the CIB's first investment commitment in a transmission project and another example of the CIB's momentum to quickly implement its $10B Growth Plan, amid broader investments in green energy solutions in British Columbia that support clean growth.

Endorsements

This project will allow Ontario to export its clean, non-emitting power to one of the largest power markets in the world and, as a result, benefit Canadians economically while also significantly contributing to greenhouse gas emissions reductions in the PJM market. The project allows Ontario to better manage peak capacity and meet future reliability needs in a more sustainable way. This is a true win-win for both Canada and the U.S., both economically and environmentally.
Ehren Cory, CEO, Canada Infrastructure Bank

The Lake Erie Connector has tremendous potential to generate customer savings, help achieve shared carbon reduction goals, and increase electricity system reliability and flexibility. We look forward to working with the CIB, provincial and federal governments to support a more affordable, customer-focused system for Ontarians. 
Jon Jipping, EVP & COO, ITC Investment Holdings Inc., a subsidiary of Canadian-based Fortis Inc. 

We are encouraged by this recent announcement by the Canada Infrastructure Bank. Mississaugas of the Credit First Nation has an interest in projects within our historic treaty lands that have environmental benefits and that offer economic participation for our community.
Chief Stacey Laforme, Mississaugas of the Credit First Nation

While our evaluation of the project continues, we recognize this project can contribute to the economic resilience of our Shareholder, the Mississaugas of the Credit First Nation. Subject to the successful conclusion of our collaborative efforts with ITC, we look forward to our involvement in building the necessary infrastructure that enable Ontario's economic engine.
Leonard Rickard, CEO, Mississaugas of the Credit Business Corporation

The Lake Erie Connector demonstrates the advantages of public-private partnerships to develop critical infrastructure that delivers greater value to Ontarians. Connecting Ontario's electricity grid to the PJM electricity market will bring significant, tangible benefits to our province. This new connection will create high-quality jobs, improve system flexibility, and allow Ontario to export more excess electricity to promote cost-savings for Ontario's electricity consumers.
Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs

With the US pledging to achieve a carbon-free electrical grid by 2035, Canada has an opportunity to export clean power, helping to reduce emissions, maximizing clean power use and making electricity more affordable for Canadians. The Lake Erie Connector is a perfect example of that. The Canada Infrastructure Bank's investment will give Ontario direct access to North America's largest electricity market - 13 states and D.C. This is part of our infrastructure plan to create jobs across the country, tackle climate change, and increase Canada's competitiveness in the clean economy, alongside innovation programs like the Hydrogen Innovation Fund that foster clean technology.

Quick Facts

• The Lake Erie Connector is a 1,000 megawatt, 117 kilometre long underwater transmission line connecting Ontario and Pennsylvania.
• The PJM Interconnection is a regional transmission organization coordinating the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
• The project will help to reduce electricity system costs for customers in Ontario, and aligns with ongoing consultations on industrial electricity pricing and programs, while helping to support future capacity needs.
• The CIB is mandated to invest CAD $35 billion and attract private sector investment into new revenue-generating infrastructure projects that are in the public interest and support Canadian economic growth.
• The investment commitment is subject to final due diligence and approval by the CIB's Board.

Related News

• Electricity Forum News

• EV Infrastructure News

Montana New Energy Economy integrates grid modernization, renewable energy, storage, and demand response to cut costs, create jobs, enable electric transportation, and reduce emissions through utility-scale efficiency, real-time markets, and distributed resources.

Key Points

Plan to modernize Montana's grid with renewables, storage and efficiency to lower costs, cut emissions and add jobs.

✅ Grid modernization enables real-time markets and demand response

✅ Utility-scale renewables paired with storage deliver firm power

✅ Efficiency and DERs cut peaks, costs, and pollution

Over the next decade, Montana ratepayers will likely invest over a billion dollars into what is now being called the new energy economy.

Not since Edison electrified a New York City neighborhood in 1882 have we had such an opportunity to rethink the way we commercially produce and consume electric energy.

Looking ahead, the modernization of Edison’s grid will lower the consumer costs, creating many thousands of permanent, well-paying jobs. It will prepare the grid for significant new loads like America going electric in transportation, and in doing so it will reduce a major source of air pollution known to directly threaten the core health of Montana and the planet.

Energy innovation makes our choices almost unrecognizable from the 1980s, when Montana last built a large, central-station power plant. Our future power plants will be smaller and more modular, efficient and less polluting — with some technologies approaching zero operating emissions.

The 21st Century grid will optimize how the supply and demand of electricity is managed across larger interconnected service areas. Utilities will interact more directly with their consumers, with utility trends guiding a new focus on providing a portfolio of energy services versus simply spinning an electric meter. Investments in utility-scale energy efficiency — LED streetlights, internet-connected thermostats, and tightening of commercial building envelopes among many — will allow consumers to directly save on their monthly bills, to improve their quality of life, and to help utilities reduce expensive and excessive peaks in demand.

The New Energy Economy will be built not of one single technology, but of many — distributed over a modernized grid across the West that approaches a real-time energy market, as provinces pursue market overhauls to adapt — connecting consumers, increasing competition, reducing cost and improving reliability.

Boldly leading the charge is a new and proven class of commercial generation powered by wind and solar energy, the latter of which employs advanced solid-state electronics, free fuel and no emissions or moving parts. Montana is blessed with wind and solar energy resources, so this is a Made-in-Montana energy choice. Note that these plants are typically paired with utility-scale energy storage investments — also an essential building block of the 21st century grid — to deliver firm, on-demand electric service.

Once considered new age and trendy, these production technologies are today competent and shovel-ready. Their adoption will build domestic energy independence. And, they are aggressively cost-competitive. For example, this year the company ISO New England — operator of a six-state grid covering all of New England — released an all-source bid for new production capacity. Unexpectedly, 100% of the winning bids were large solar electric power and storage projects, as coal and nuclear disruptions continue to shape markets. For the first time, no applications for fossil-fueled generation cleared auction.

By avoiding the burning of traditional fuels, the new energy technologies promise to offset and eventually eliminate the current 1,500 million metric tons of damaging greenhouse gases — one-quarter of the nation’s total — that are annually injected into the atmosphere by our nation’s current electric generation plants. The first step to solving the toughest and most expensive environmental issues of our day — be they costly wildfires or the regional drought that threatens Montana agriculture and outdoor recreation — is a thoughtful state energy policy, built around the new energy economy, that avoids pitfalls like the Wyoming clean energy bill now proposed.

Important potential investments not currently ready for prime time are also on the horizon, including small and highly efficient nuclear innovation in power plants — called small modular reactors (SMR) — designed to produce around-the-clock electric power with zero toxic emissions.

The nation’s first demonstration SMR plant is scheduled to be built sometime late this decade. Fingers are crossed for a good outcome. But until then, experts agree that big questions on the future commercial viability of nuclear remain unanswered: What will be SMR’s cost of electricity? Will it compete? Where will we source the refined fuel (most uranium is imported), and what will be the plan for its safe, permanent disposal?

So, what is Montana’s path forward? The short answer is: Hopefully, all of the above.

Key to Montana’s future investment success will be a respectful state planning process that learns from Texas grid improvements to bolster reliability.

Montanans deserve a smart and civil and bipartisan conversation to shape our new energy economy. There will be no need, nor place, for parties that barnstorm the state about "radical agendas" and partisan name calling – that just poisons the conversation, eliminates creative exchange and pulls us off task.

The task is to identify and vet good choices. It’s about permanently lowering energy costs to consumers. It’s about being business smart and business friendly. It’s about honoring the transition needs of our legacy energy communities. And, it’s about stewarding our world-class environment in earnest. That’s the job ahead.

Related News

• Electricity Forum News

• Energy Policy News

US Nuclear Generating Costs 2017 show USD33.50/MWh for nuclear energy, the lowest since 2008, as capital expenditures, fuel costs, and operating costs declined after license renewals and uprates, supporting a reliable, low-carbon grid.

Key Points

The 2017 US nuclear average was USD33.50/MWh, lowest since 2008, driven by reduced capital, fuel, and operating costs.

✅ Average cost USD33.50/MWh, lowest since 2008

✅ Capital, fuel, O&M costs fell sharply since 2012 peak

✅ License renewals, uprates, market reforms shape competitiveness

Average total generating costs for nuclear energy in 2017 in the USA were at their lowest since 2008, according to a study released by the Nuclear Energy Institute (NEI), amid a continuing nuclear decline debate in other regions.

The report, Nuclear Costs in Context, found that in 2017 the average total generating cost - which includes capital, fuel and operating costs - for nuclear energy was USD33.50 per megawatt-hour (MWh), even as interest in next-generation nuclear designs grows among stakeholders. This is 3.3% lower than in 2016 and more than 19% below 2012's peak. The reduction in costs since 2012 is due to a 40.8% reduction in capital expenditures, a 17.2% reduction in fuel costs and an 8.7% reduction in operating costs, the organisation said.

The year-on-year decline in capital costs over the past five years reflects the completion by most plants of efforts to prepare for operation beyond their initial 40-year licence. A few major items - a series of vessel head replacements; steam generator replacements and other upgrades as companies prepared for continued operation, and power uprates to increase output from existing plants - caused capital investment to increase to a peak in 2012. "As a result of these investments, 86 of the [USA's] 99 operating reactors in 2017 have received 20-year licence renewals and 92 of the operating reactors have been approved for uprates that have added over 7900 megawatts of electricity capacity. Capital spending on uprates and items necessary for operation beyond 40 years has moderated as most plants are completing these efforts," it says.

Since 2013, seven US nuclear reactors have shut down permanently, with the Three Mile Island debate highlighting wider policy questions, and another 12 have announced their permanent shutdown. The early closure for economic reasons of reliable nuclear plants with high capacity factors and relatively low generating costs will have long-term economic consequences, the report warns: replacement generating capacity, when needed, will produce more costly electricity, fewer jobs that will pay less, and, for net-zero emissions objectives, more pollution, it says.

NEI Vice President of Policy Development and Public Affairs John Kotek said the "hardworking men and women of the nuclear industry" had done an "amazing job" reducing costs through the institute's Delivering the Nuclear Promise campaign and other initiatives, in line with IAEA low-carbon lessons from the pandemic. "As we continue to face economic headwinds in markets which do not properly compensate nuclear plants, the industry has been doing its part to reduce costs to remain competitive," he said.

"Some things are in urgent need of change if we are to keep the nation's nuclear plants running and enjoy their contribution to a reliable, resilient and low-carbon grid. Namely, we need to put in place market reforms that fairly compensate nuclear similar to those already in place in New York, Illinois and other states," Kotek added.

Cost information in the study was collected by the Electric Utility Cost Group with prior years converted to 2017 dollars for accurate historical comparison.

Related News

• Electricity Forum News

• Power Generation News