Proposed link for northeast renewable projects

New Brunswick Small Modular Reactors promise clean energy, jobs, and economic growth, say NB Power, ARC Nuclear, and Moltex Energy; critics cite cost overruns, nuclear waste risks, market viability, and reliance on government funding.

Key Points

Compact reactors proposed in NB to deliver low-carbon power and jobs; critics warn of costs, waste, and market risks.

✅ Promised jobs, exports, and net-zero support via NB Power partnerships

✅ Critics cite cost overruns, nuclear waste, and weak market demand

✅ Government funding pivotal; ARC and Moltex advance licensing

When Mike Holland talks about small modular nuclear reactors, he sees dollar signs.

When the Green Party hears about them, they see danger signs.

The loquacious Progressive Conservative minister of energy development recently quoted NB Power's eye-popping estimates of the potential economic impact of the reactors: thousands of jobs and a $1 billion boost to the provincial economy.

"New Brunswick is positioned to not only participate in this opportunity, but to be a world leader in the SMR field," Holland said in the legislature last month.

'Huge risk' nuclear deal could let Ontario push N.B. aside, says consultant
'Many issues' with modular nuclear reactors says environmental lawyer
Green MLAs David Coon and Kevin Arseneau responded cheekily by ticking off the Financial and Consumer Services Commission's checklist on how to spot a scam.

Is the sales pitch from a credible source? Is the windfall being promised by a reputable institution? Is the risk reasonable?

For small nuclear reactors, they said, the answer to all those questions is no. 

"The last thing we need to do is pour more public money down the nuclear-power drain," Coon said, reminding MLAs of the Point Lepreau refurbishment project that went $1 billion over budget.

The Greens aside, New Brunswick politicians have embraced small modular reactors as part of a broader premiers' nuclear initiative to develop SMR technology, which they say can both create jobs and help solve the climate crisis.

Smaller and cheaper, supporters say
They're "small" because, depending on the design, they would generate from three to 300 megawatts of electricity, less than, for example, Point Lepreau's 660 megawatts.

It's the modular design that is supposed to make them more affordable, as explained in next-gen nuclear guides, with components manufactured elsewhere, sometimes in existing factories, then shipped and assembled. 

Under Brian Gallant, the Liberals handed $10 million to two Saint John companies working on SMRs, ARC Nuclear and Moltex Energy.

Greens point to previous fiascoes
The Greens and other opponents of nuclear power fear SMRS are the latest in a long line of silver-bullet fiascoes, from the $23 million spent on the Bricklin in 1975 to $63.4 million in loans and loan guarantees to the Atcon Group a decade ago.

"It seems that [ARC and Moltex] have been targeting New Brunswick for another big handout ... because it's going to take billions of dollars to build these things, if they ever get off the drawing board," said Susan O'Donnell, a University of New Brunswick researcher.

O'Donnell, who studies technology adoption in communities, is part of a small new group called the Coalition for Responsible Energy Development formed this year to oppose SMRs.

"What we really need here is a reasonable discussion about the pros and cons of it," she said.

Government touts economic spinoffs
According to the Higgs government's throne speech last month, if New Brunswick companies can secure just one per cent of the Canadian market for small reactors, the province would see $190 million in revenue. 

The figures come from a study conducted for NB Power by University of Moncton economist Pierre-Marcel Desjardins.

But a four-page public summary does not include any sales projections and NB Power did not provide them to CBC News. 

"What we didn't see was a market analysis," O'Donnell said. "How viable is the market? … They're all based on a hypothetical market that probably doesn't exist."

O'Donnell said her group asked for the full report but was told it's confidential because it contains sensitive commercial information.

Holland said he's confident there will be buyers. 

"It won't be hard to find communities that will be looking for a cost effective, affordable, safe alternative to generate their electricity and do it in a way that emits zero emissions," he said.

SMRs come in different sizes and while some proponents talk about using "micro" reactors to provide electricity to remote northern First Nations communities, ARC and Moltex plan larger models to sell to power utilities looking to shift away from coal and gas.

"We have utilities and customers across Canada, where Ontario's first SMR groundbreaking has occurred already, across the United States, across Asia and Europe saying they desperately want a technology like this," said Moltex's Saint John-based CEO for North America Rory O'Sullivan. 

"The market is screaming for this product," he said, adding "all of the utilities" in Canada are interested in Moltex's reactors

ARC's CEO Norm Sawyer is more specific, guessing 30 per cent of his SMR sales will be in Atlantic Canada, 30 per cent in Ontario, where Darlington SMR plans are advancing, and 40 per cent in Alberta and Saskatchewan — all provincial power grids.

O'Donnell said it's an important question because without a large number of guaranteed sales, the high cost of manufacturing SMRs would make the initiative a money-loser. 

The cost of building the world's only functioning SMR, in Russia, was four times what was expected. 

An Australian government agency said initial cost estimates for such major projects "are often initially too low" and can "overrun." 

Up-front costs can be huge
University of British Columbia physicist M.V. Ramana, who has authored studies on the economics of nuclear power, said SMRs face the same financial reality as any large-scale manufacturing.

"You're going to spend a huge amount of money on the basic fixed costs" at the outset, he said, with costs per unit becoming more viable only after more units are built and sold. 

He estimates a company would have to build and sell more than 700 SMRs to break even, and said there are not enough buyers for that to happen. 

But Sawyer said those estimates don't take into account technological advances.

"A lot of what's being said ... is really based on old technology," he said, estimating ARC would be viable even if it sold an amount of reactors in the low double digits. 

O'Sullivan agrees.

"In fact, just the first one alone looks like it will still be economical," he said. "In reality, you probably need a few … but you're talking about one or two, maximum three [to make a profit] because you don't need these big factories."

'Paper designs' prove nothing, says expert
Ramana doesn't buy it. 

"These are all companies that have been started by somebody who's been in the nuclear industry for some years, has a bright idea, finds an angel investor who's given them a few million dollars," he said.

"They have a paper design, or a Power Point design. They have not built anything. They have not tested anything. To go from that point … to a design that can actually be constructed on the field is an enormous amount of work." 

Both CEOs acknowledge the skepticism about SMRs.

'The market is screaming for this product,' said Moltex’s Saint John-based CEO for North America, Rory O’Sullivan. (Brian Chisholm, CBC)
"I understand New Brunswick has had its share of good investments and its share of what we consider questionable investments," said Sawyer, who grew up in Rexton.

But he said ARC's SMR is based on a long-proven technology and is far past the on-paper design stage "so you reduce the risk." 

Moltex is now completing the first phase of the Canadian Nuclear Safety Commission's review of its design, a major hurdle. ARC completed that phase last year.

But, Ramana said there are problems with both designs. Moltex's molten salt model has had "huge technical challenges" elsewhere while ARC's sodium-cooled system has encountered "operational difficulties."

Ottawa says nuclear is needed for climate goals
The most compelling argument for looking at SMRs may be Ottawa's climate change goals, and international moves like the U.K.'s green industrial revolution plan point to broader momentum.  

The national climate plan requires NB Power to phase out burning coal at its Belledune generating station by 2030. It's scrambling to find a replacement source of electricity.

The Trudeau government's throne speech in October promised to "support investments in renewable energy and next-generation clean energy and technology solutions."

And federal Natural Resources Minister Seamus O'Regan told CBC earlier this year that he's "very excited" about SMRs and has called nuclear key to climate goals in Canada as well.

"We have not seen a model where we can get to net-zero emissions by 2050 without nuclear,"  he said.

O'Donnell said while nuclear power doesn't emit greenhouse gases, it's hardly a clean technology because of the spent nuclear fuel waste. 

Government support is key 
She also wonders why, if SMRs make so much sense, ARC and Moltex are relying so much on government money rather than private capital.

Holland said "the vast majority" of funding for the two companies "has to come from private sector investments, who will be very careful to make sure they get a return on that investment."

Sawyer said ARC has three dollars for every dollar it has received from the province, and General Electric has a minority ownership stake in its U.S.-based parent company.

O'Sullivan said Moltex has attracted $5 million from a European engineering firm and $6 million from "the first-ever nuclear crowdfunding campaign." 

But he said for new technologies, including nuclear power, "you need government to show policy support.

"Nuclear technology has always been developed by governments around the world. This is a very new change to have an industry come in and lead this, so private investors can't take the risk to do that on their own," he said. 

So far, Ottawa hasn't put up any funding for ARC or Moltex. During the provincial election campaign, Higgs implied federal money was imminent, but there's been no announcement in the almost three months since then.

Last month the federal government announced $20 million for Terrestrial Energy, an Ontario company working on SMRs, alongside OPG's commitment to SMRs in the province, underscoring momentum.

"We know we have the best technology pitch," O'Sullivan said. "There's others that are slightly more advanced than us, but we have the best overall proposition and we think that's going to win out at the end of the day."

But O'Donnell said her group plans to continue asking questions about SMRs. 

"I think what we really need is to have an honest conversation about what these are so that New Brunswickers can have all the facts on the table," she said.

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UK Energy Network Profits are under scrutiny as Ofgem price controls, Citizens Advice claims, and National Grid margins spark debate over monopolies, allowed returns, consumer bills, rebates, and future investment under tougher regulation.

Key Points

UK Energy Network Profits are returns set by Ofgem for regulated grid operators, shaping consumer bills and investment

✅ Ofgem sets allowed returns for monopoly networks via price controls

✅ Dispute over interest rates, bond yields, and risk premiums

✅ Reforms proposed: shorter controls, tougher investor incentives

Companies that run Britain’s electricity and gas networks, including National Grid, are making “eye-watering” profits at the expense of households, according to a well-known consumer group.

Citizens Advice believes £7.5bn in “unjustified” profits should be returned to consumers who pay for network costs via their electricity and gas bills, with parallels seen in a deferred BC Hydro costs report abroad, although its figures have been contested by the energy industry and regulator.

Ownership of electricity and gas networks came under the spotlight in the run-up to June’s general election, after the Labour party said in its manifesto it would bring both national and regional grid infrastructure to back into public ownership, amid wider debates about grid privatization concerns elsewhere, over time.

Electricity sector privatisation began in 1990 and the gas industry was privatised in 1986. Energy network companies — which own and operate the cables and wires that help deliver electricity and gas to homes and businesses — are in effect monopolies that are regulated by Ofgem. Ofgem evaluates what their costs, including the cost of capital to finance investments, might be over an eight-year “price control” period, similar to determinations like the OEB decision on Hydro One rates in Ontario, Canada. Citizens Advice claims many of the regulator’s calculations for the most recent price control went “considerably in networks’ financial favour”.

It believes assumptions Ofgem made about factors such as the future path of interest rates and returns on government bonds were too generous, with international contrasts like power theft challenges in India illustrating different risk contexts, as was the regulator’s assessment of the risk associated with operating a network company. 

These “generous” assumptions will lead to network companies making average profit margins of 19 per cent and an average return of 10 per cent for their investors at the expense of consumers, Citizens Advice claims in a report published on Wednesday, which recommends a shorter price control period to allow for more accurate forecasting.

“Decisions made by Ofgem have allowed gas and electricity network companies to make sky-high profits that we’ve found are not justified by their performance,” said Gillian Guy, chief executive of Citizens Advice. Ofgem defended its regulatory regime, saying it helped to cut costs, improve reliability and customer satisfaction. 

“Ofgem has already cut costs to consumers by 6 per cent in the current price control and secured a rebate of over £4.5bn from network companies and is engaging with the industry to deliver further savings, with some regions seeing Ontario electricity rate reductions for businesses as well,” said Dermot Nolan, chief executive of the energy regulator.

Mr Nolan insisted the next price controls would be “tougher for investors”. The current price controls for the gas and electricity transmission networks, plus gas distribution, run until 2021 and until 2023 for local electricity distribution networks.

“While we don’t agree with its modelling and the figures it has produced, the Citizens Advice report raises some important issues about network regulation which will be addressed in the next control,” Mr Nolan said.

The Energy Networks Association, a trade body, refuted the claims of Citizens Advice, insisting that costs had fallen by 17 per cent in real terms since privatisation. The current regulatory framework was established after a public consultation, it said, adding that today’s report repeated several old claims that had previously been rejected by the Competition and Markets Authority.

“Our energy networks are among the most reliable and lowest cost in the world and their performance has never been better. In the next six years energy network companies are forecasted to deliver £45bn of investment in the UK economy,” a spokesman for the networks association added. National Grid said that since 2013 it had generated savings of £460m for bill payers.

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Iran Electricity Grid Synchronization enables regional interconnection, cross-border transmission, and Caspian-Europe energy corridors, linking Iraq, Azerbaijan, Russia, and Qatar to West Asia and European markets with reliable, flexible power exchange.

Key Points

Iran's initiative to link West Asian and European power grids for trade, transit, reliability, and regional influence.

✅ Synchronizes grids with Iraq, Azerbaijan, Russia, and potential Qatar link

✅ Enables east-to-Europe electricity transit via Caspian energy corridors

✅ Backed by gas-fueled and combined-cycle generation capacity

Following a plan for becoming West Asia’s electricity hub, Iran has been taking serious steps for joining its electricity network with neighbors in the past few years.

The Iranian Energy Ministry has been negotiating with the neighboring countries including Iraq for the connection of their power networks with Iran, discussing Iran-Iraq energy cooperation as well as ties with Russia, Afghanistan, Azerbaijan, and Qatar to make them enable to import or transmit their electricity to new destination markets through Iran.

The synchronization of power grids with the neighboring countries, not only enhances Iran’s electricity exchanges with them, but it will also increase the political stance of the country in the region.

So far, Iran’s electricity network has been synchronized with Iraq, where Iran is supplying 40% of Iraq's power today, and back in September, the Energy Minister Reza Ardakanian announced that the electricity networks of Russia and Azerbaijan are the next in line for becoming linked with the Iranian grid in the coming months.

“Within the next few months, the study project of synchronization of the electricity networks of Iran, Azerbaijan, and Russia will be completed and then the executive operations will begin,” the minister said.

Meanwhile, Ardakanian and Qatari Minister of State for Energy Affairs Saad Sherida Al-Kaabi held an online meeting in late September to discuss joining the two countries' electricity networks via sea.

During the online meeting, Al-Kaabi said: "Electricity transfer between the two countries is possible and this proposal should be worked on.”

Now, taking a new step toward becoming the region’s power hub, Iran has suggested becoming a bridge between East and Europe for transmitting electricity.

In a virtual conference dubbed 1st Caspian Europe Forum hosted by Berlin on Thursday, the Iranian energy minister has expressed the country’s readiness for joining its electricity network with Europe.

"We are ready to connect Iran's electricity network, as the largest power generation power in West Asia, with the European countries and to provide the ground for the exchange of electricity with Europe," Ardakanian said addressing the online event.

Iran's energy infrastructure in the oil, gas, and electricity sectors can be used as good platforms for the transfer of energy from east to Europe, he noted.

In the event, which was aimed to study issues related to the development of economic cooperation, especially energy, between the countries of the Caspian Sea region, the official added that Iran, with its huge energy resources and having skilled manpower and advanced facilities in the field of energy, can pave the ground for the prosperity of international transport and energy corridors.

"In order to help promote communication between our landlocked neighbors with international markets, as Uzbekistan aims to export power to Afghanistan across the region, we have created a huge transit infrastructure in our country and have demonstrated in practice our commitment to regional development and peace and stability," Ardakanian said.

He pointed out that having a major percentage of proven oil and gas resources in the world, regional states need to strengthen relations in a bid to regulate production and export policies of these huge resources and potentially play a role in determining the price and supply of these resources worldwide.

“EU countries can join our regional cooperation in the framework of bilateral or multilateral mechanisms such as ECO,” he said.

Given the growing regional and global energy needs and the insufficient investment in the field, with parts of Central Asia facing severe electricity shortages today, as well as Europe's increasing needs, this area can become a sustainable area of cooperation, he noted.

Ardakanian also said that by investing in energy production in Iran, Europe can meet part of its future energy needs on a sustainable basis.

In Iraq, plans for nuclear power plants are being pursued to tackle chronic electricity shortages, reflecting parallel efforts to diversify generation.

Iran currently has electricity exchange with Armenia, Azerbaijan, Iraq, where grid rehabilitation deals have been finalized, Turkmenistan, and Afghanistan.

The country’s total electricity exports vary depending on the hot and cold seasons of the year, since during the hot season which is the peak consumption period, the country’s electricity exports decreases, however electrical communication with neighboring countries continues.

Enjoying abundant gas resources, which is the main fuel for the majority of the country’s power plants, Iran has the capacity to produce about 85,500 megawatts [85.5 gigawatts (GW)] of electricity.

Currently, combined cycle power plants account for the biggest share in the country’s total power generation capacity as Iran is turning thermal plants to combined cycle to save energy, followed by gas power plants.

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Minnesota Electric Cooperatives are driving grid innovation with smart meters, time-of-use pricing, demand response, and energy storage, including iron-air batteries, to manage peak loads, integrate wind and solar, and cut costs for rural members.

Key Points

Member-owned utilities piloting load management, meters, and storage to integrate wind and solar, cutting peak demand.

✅ Time-of-use pricing pilots lower bills and shift peak load.

✅ Iron-air battery tests add multi-day, low-cost energy storage.

✅ Smart meters enable demand response across rural co-ops.

Minnesota electric cooperatives have quietly emerged as laboratories for clean grid innovation, outpacing investor-owned utilities on smart meter installations, time-based pricing pilots, and experimental battery storage solutions.

“Co-ops have innovation in their DNA,” said David Ranallo, a spokesperson for Great River Energy, a generation and distribution cooperative that supplies power to 28 member utilities — making it one of the state’s largest co-op players.

Minnesota farmers helped pioneer the electric co-op model more than a century ago, similar to modern community-generated green electricity initiatives, pooling resources to build power lines, transformers and other equipment to deliver power to rural parts of the state. Today, 44 member-owned electric co-ops serve about 1.7 million rural and suburban customers and supply almost a quarter of the state’s electricity.

Co-op utilities have by many measures lagged on clean energy. Many still rely on electricity from coal-fired power plants. They’ve used political clout with rural lawmakers to oppose new pollution regulations and climate legislation, and some have tried to levy steep fees on customers who install solar panels.

Where they are emerging as innovators is with new models and technology for managing electric grid loads — from load-shifting water heaters to a giant experimental battery made of iron. The programs are saving customers money by delaying the need for expensive new infrastructure, and also showing ways to unlock more value from cheap but variable wind and solar power.

Unlike investor-owned utilities, “we have no incentive to invest in new generation,” said Darrick Moe, executive director of the Minnesota Rural Electric Association. Curbing peak energy demand has a direct financial benefit for members.

Minnesota electric cooperatives have launched dozens of programs, such as the South Metro solar project, in recent years aimed at reducing energy use and peak loads, in particular. They include:

Cost calculations are the primary driver for electric cooperatives’ recent experimentation, and a lighter regulatory structure and evolving electricity market reforms have allowed them to act more quickly than for-profit utilities.

“Co-ops and [municipal utilities] can act a lot more nimbly compared to investor-owned utilities … which have to go through years of proceedings and discussions about cost-recovery,” said Gabe Chan, a University of Minnesota associate professor who has researched electric co-ops extensively. Often, approval from a local board is all that’s required to launch a venture.

Great River Energy’s programs, which are rebranded and sold through member co-ops, yielded more than 101 million kilowatt-hours of savings last year — enough to power 9,500 homes for a year.

Beyond lowering costs for participants and customers at large, the energy-saving and behavior-changing programs sometimes end up being cited as case studies by larger utilities considering similar offerings. Advocates supporting a proposal by the city of Minneapolis and CenterPoint Energy to allow residents to pay for energy efficiency improvements on their utility bills through distributed energy rebates used several examples from cooperatives.

Despite the pace of innovation on load management, electric cooperatives have been relatively slow to transition from coal-fired power. More than half of Great River Energy’s electricity came from coal last year, and Dairyland Power, another major power wholesaler for Minnesota co-ops, generated 70% of its energy from coal. Meanwhile, Xcel Energy, the state’s largest investor-owned utility, has already reduced coal to about 20% of its energy mix.

The transition to cleaner power for some co-ops has been slowed by long-term contracts with power suppliers that have locked them into dirty power. Others have also been stalled by management or boards that have been resistant to change. John Farrell, director of the Institute for Local Self-Reliance’s Energy Democracy program, said generalizing co-ops is difficult. 

“We’ve seen some co-ops that have got 75-year contracts for coal, that are invested in coal mines and using their newsletter to deny climate change,” he said. “Then you see a lot of them doing really amazing things like creating energy storage systems … and load balancing [programs], because they are unique and locally managed and can have that freedom to experiment without having to go through a regulatory process.”

Great River Energy, for its part, says it intends to reach 54% renewable generation by 2025, while some communities, like Frisco, Colorado, are targeting 100% clean electricity by specific dates. Its members recently voted to sell North Dakota’s largest coal plant, but the arrangement involves members continuing to buy power from the new owners for another decade.

The cooperative’s path to clean power could become clearer if its experimental iron-air battery project is successful. The project, the first of its kind in the country, is expected to be completed by 2023.

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Spain Wind Turbine Factory Shutdowns disrupt manufacturing as Vestas, Siemens Gamesa, and Nordex halt Spanish plants amid COVID-19 lockdowns, straining supply chains and renewables projects across Europe, with partial operations and maintenance continuing.

Key Points

COVID-19 lockdowns pause Spanish wind factories by Vestas, Siemens Gamesa, and Nordex, disrupting supply chains.

✅ Vestas, Siemens Gamesa, Nordex halt Spanish manufacturing

✅ Service and maintenance continue under safety protocols

✅ Supply chain and project timelines face delays in Europe

Europe’s largest wind turbine makers on Wednesday said they had shut down more factories in Spain, a major hub for the continent’s renewables sector, in response to an almost total lockdown in the country to contain the coronavirus outbreak as the Covid-19 crisis disrupts the sector.

Denmark’s Vestas, the world No.1, has suspended production at its two Spanish plants, a spokesman told Reuters, adding that its service and maintenance business was still working. Vestas has also paused manufacturing and construction in India, which is under a nationwide lockdown too, he said, and similar disruptions could stall U.S. utility solar projects this year.

Top rival Siemens Gamesa, known for its offshore wind turbine lineup, suspended production at six Spanish factories on Monday, bringing total closures there to eight, a spokeswoman said.

Four components factories are still partially up and running, at Reinosa on the north coast, Cuenca near Madrid, Mungia and Siguiero, she added.

Germany’s Nordex, the No.8 globally which is 36% owned by Spain’s Acciona, has now shuttered all of its production in Spain, even as new projects like Enel’s 90MW build move ahead, including two nacelle casing factories in Barasoain and Vall d’Uixo, as well as a rotor blade site in Lumbier.

“Production is no longer active,” a spokeswoman said in response to a Reuters query.

The new closures take the number of idled wind power factories on the continent to 19, all in Spain and Italy, the European countries worst hit by the pandemic, with investments at risk across the sector.

Spain is second only to Italy in terms of numbers of coronavirus-related fatalities and restrictions have become even stricter in the country’s third week of lockdown at a time when renewables surpassed fossil fuels for the first time in Europe.

“Some factories have temporarily paused activity as a precautionary step to strengthen sanitary measures within the sites and guarantee full compliance with government recommendations,” industry association WindEurope said, noting that wind power grows in some markets despite the pandemic.

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EU Power Market Overhaul targets soaring electricity prices by decoupling gas from power, boosting renewables, refining price caps, and stabilizing grids amid inflation, supply shocks, droughts, nuclear outages, and intermittent wind and solar.

Key Points

EU plan to redesign electricity pricing, curb gas-driven costs, boost renewables, and protect consumers from volatility.

✅ Decouples power prices from marginal gas generation

✅ Caps non-gas revenues to fund consumer relief

✅ Supports grid stability with storage, demand response, LNG

While energy prices are soaring around the world, Europe is in a particularly tight spot. Its heavy dependence on Russian gas -- on top of droughts, heat waves, an unreliable fleet of French nuclear reactors and a continent-wide shift to greener but more intermittent sources like solar and wind -- has been driving electricity bills up and feeding the highest inflation in decades. As Europe stands on the brink of a recession, and with the winter heating season approaching, officials are considering a major overhaul of the region’s power market to reflect the ongoing shift from fossil fuels to renewables.

1. How is electricity priced? 
Unlike oil or natural gas, there’s no efficient way to save lots of electricity to use in the future, though projects to store electricity in gas pipes are emerging. Commercial use of large-scale batteries is still years away. So power prices have been set by the availability at any given moment. When it’s really windy or sunny, for example, then more is produced relatively cheaply and prices are lower. If that supply shrinks, then prices rise because more generators are brought online to help meet demand -- fueled by more expensive sources. The way the market has long worked is that it is that final technology, or type of plant, needed to meet the last unit of consumption that sets the price for everyone. In Europe this year, that has usually meant natural gas. 

2. What is the relationship between power and gas? 
Very close. Across western Europe, gas plants have been a vital part of the energy infrastructure for decades, with Irish price spikes highlighting dispatchable power risks, fed in large part by supplies piped in from Siberia. Gas-fired plants were relatively quick to build and the technology straightforward, at least compared with nuclear plants and burns cleaner than coal. About 18% of Europe’s electricity was generated at gas plants last year; in 2020 about 43% of the imported gas came from Russia. Even during the depths of the Cold War, there’d never been a serious supply problem -- until the relationship with Russia deteriorated this year after it invaded Ukraine. Diversifying away from Russia, such as by increasing imports of liquefied natural gas, requires new infrastructure that takes a lot of time and money.

3. Why does it work this way? 
In theory, the relationship isn’t different from that with coal, for example. But production hiccups and heatwave curbs on plants from nuclear in France to hydro in Spain and Norway significantly changed the generation picture this year, and power hit records as plants buckled in the heat. Since coal-fired and nuclear plants are generally running all the time anyway, gas plants were being called upon more often -- at times just to keep the lights on as summer temperatures hit records. And with the war in Ukraine resulting in record gas prices, that pushed up overall production costs. It’s that relationship that has made the surging gas price the driver for electricity prices. And since the continent is all connected, it has pushed up prices across the region. The value of the European power market jumped threefold last year, to a record 836 billion euros ($827 billion today).

4. What’s being considered? 
With large parts of European industry on its knees and households facing jumps in energy bills of several hundred percent, as record electricity prices ripple through markets, the pressure on governments and the European Union to intervene has never been higher. One major proposal is to impose a price cap on electricity from non-gas producers, with the difference between that and the market price channeled to relief for consumers. While it sounds simple, any such changes would rip up a market design that’s worked for decades and could threaten future investments because of unintended consequences.

5. How did this market evolve?
The Nordic region and the British market were front-runners in the 1990s, then Germany followed and is now the largest by far. A trader can buy and sell electricity delivered later on same day in blocks of an hour or even down to 15-minute periods, to meet sudden demand or take advantage of price differentials. The price for these contracts is decided entirely by the supply and demand, how much the wind is blowing or which coal plants are operating, for example. Demand tends to surge early in the morning and late afternoon. This system was designed when fossil fuels provided the bulk of power. Now there are more renewables, which are less predictable, with wind and solar surpassing gas in EU generation last year, and the proposed changes reflect that shift. 

6. What else have governments done?
There are also traders who focus on longer-dated contracts covering periods several years ahead, where broader factors such as expected economic output and the extent to which renewables are crowding out gas help drive prices. This year’s wild price swings have prompted countries including Germany, Sweden and Finland to earmark billions of euros in emergency liquidity loans to backstop utilities hit with sudden margin calls on their trading.

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