The U.K. risks power shortages because utilities may react to Europe’s toughest carbon-emissions rules by closing plants without replacing them.
The amount of electricity available over peak demand may drop below 2 percent next year, the lowest level in western Europe, the nation’s energy regulator says. Centrica Plc, the biggest U.K. supplier, says investment in new generating capacity has “ground to a halt.”
U.K. closures, already running at a record pace, may accelerate after a 2016 deadline to cut carbon emissions from old coal-fired generators. While Germany now gets 24 percent of its power from renewable energy after government policies encouraged the building of everything from wind farms to solar panels, in the U.K. the proportion is 12 percent.
“We will be skating on very thin ice and there won’t be the resilience or the flexibility on the system to cope with demand shocks like cold weather,” said John Roberts, the London-based counsel for the Royal Academy of Engineering. Uncertainty over policy means “generators are going to sit on their hands and not invest,” he said.
Coal-fired plants totaling 13 gigawatts are at risk of closing by 2019, according to the Confederation of U.K. Coal Producers in Wakefield, England. That’s in addition to the 8.2 gigawatts shut in the past 15 months. One gigawatt can supply about 2 million European homes.
U.K. power prices, already the highest in western Europe, are poised to jump 39 percent in the next five years, according to Deutsche Bank AG. The next-month contract closed at 45.84 pounds ($76.28) a megawatt-hour in London, according to broker data compiled by Bloomberg.
German benchmark prices are at their lowest in nine years. The equivalent monthly contract closed at 30.85 euros (25.81 pounds). Deutsche Bank expects 47.50 euros in the next five years.
The capacity margin, or the amount of excess supply above peak demand, may drop below the 2 percent level in 2015, according to data from the Office of Gas and Electricity Markets in London. Demand typically jumps at times of lower-than-average temperatures. Under normal weather conditions, the margin would drop below 4 percent in the winter of 2015 to 2016, from more than 6 percent now.
U.K. utilities are already paying the most in Europe to emit carbon dioxide by burning fossil fuels. The nation was the first to introduce a tax on such activities, on top of the regional carbon trading system with emissions caps for 12,000 power plants and factories from 2005.
The tax level, frozen from 2016 through 2020 by Chancellor George Osborne today, has been one of the main uncertainties for generators making investment decisions about keeping coal-fired plants open, according to Andy Houston, a principal consultant at Poeyry Oyj, the energy adviser based in Vantaa, Finland.
Utilities also need clarity over how a proposed market for backup electricity will work, Houston said from his office in London. Producers will be able to bid in an auction in December this year to offer backup power from 2018, according to the Department for Energy and Climate Change. The mechanism should start before 2018 to give utilities more certainty, said Steve Waygood, the Swindon, England-based head of environment and chemistry at the U.K. unit of RWE AG.
The program, known as a capacity market, will ensure sufficient capacity and security of supply, a spokeswoman for the DECC wrote in an e-mail March 12. The British power industry needs about 110 billion pounds of investment in the next 10 years, according to the department’s estimate.
The U.K.’s Electricity Market Reform, which came into force in December, includes mechanisms to bring new power plants onto the system, Rebecca Watson, a spokeswoman for National Grid Plc, said yesterday by e-mail. “We should also see new low carbon and renewable generation built.”
“Political uncertainty is the enemy of investment,” Centrica CEO Sam Laidlaw said March 5 at a speech in Houston. “Investment in new U.K. generating capacity has virtually ground to a halt.”
The U.K. is targeting a 15 percent share of power from renewable sources by 2020, according to the DECC. Consumers will pay 120 pounds a year to fund the move toward greener power generation, on top of their current average energy bill of 1,420 pounds, according to Which?, the consumer-lobby group in London.
“Tightening margins are not a good news story for customers,” Richard Hall, the director of strategic infrastructure at Consumer Futures, which is funded by levies on utilities and postal services, wrote in an e-mail. “As we see a reduction of surpluses, we’re likely to see higher prices.”
EU rules starting in January 2016 oblige utilities to equip plants with technology to cut emissions, or close them by 2023 or when they have run for 17,500 hours. The equipment costs at least 100 million pounds per gigawatt of capacity, according to Peter Atherton, an analyst at Liberum Capital Ltd. in London.
EON AG is the only producer to have installed the technology in the U.K. Germany’s biggest utility is carrying out the work at its 2,000-megawatt Ratcliffe plant, according to Scott Somerville, a company spokesman in Coventry, England.
The U.K. only built one coal-fired power plant since the early 1970s, so most are already reaching the end of their lives, said Houston of Poeyry, which advises the U.K. government. By 2023, “there will be very little coal left on the system in the U.K.,” he said by phone from London.
Plants closed last year included EON’s Kingsnorth station and RWE AG’s Didcot A. Both generators shut under earlier EU emissions-cutting rules.
Companies invested $55.1 billion in U.K. renewable sources in the past five years, compared with $124 billion in Germany, Europe’s biggest producer of solar and wind power, according to Bloomberg New Energy Finance in London.
Even as nations boost the share of intermittent renewable energy, the need for backup capacity remains. The most flexible alternative is gas-fired capacity, which produces power within minutes, while a coal plant may take as long as six hours, according to RWE.
“You can see the car crash happening,” said John Feddersen, the chief executive officer of Aurora Energy Research in Oxford, England. “There has been very little investment in combined cycle gas turbines for a long time. It is partly about profitability and partly about policy uncertainty.”