Britain, like Ontario, must soon decide whether to invest billions in more atomic energy

By Toronto Star


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On a day when thick fog obscures the nuclear power stations on the Somerset coast, all that hints at the disputed future of the industry is the loud buzz of generated electricity.

The Hinkley Point A station is first to fully appear as the fog slowly lifts — two square, blue buildings encasing shut-down reactors that will glow radioactive for thousands of years. The grey cement mass of B station then emerges. It is scheduled to produce electricity until it's mothballed in 2011, unless safety concerns over cracks in the reactors' graphite bricks force an earlier shutdown.

Both these sights are troubling enough for Jim Duffy, a local resident who for almost two decades has campaigned against nuclear power on this 20-hectare site on the Bristol Channel in southwestern England.

But perhaps his worst fear is for what else a fading fog may one day reveal: a third nuclear power station on what is now a vacant field. The spot is considered a candidate if the government backs the building of new nuclear stations.

Duffy, 52, strikes a weary note when considering the tough campaign ahead against a nuclear industry that until recently seemed all but beaten.

"I don't relish it," says Duffy, whose safety campaigns helped shut the 35-year-old A station in 1999. "I'd rather the whole thing just die down. But we'll have a go, if we have to."

British Prime Minister Tony Blair this week announced an energy policy review that "will include specifically the issue of whether we facilitate the development of a new generation of nuclear power stations."

The review will address the same sort of question the Ontario Power Authority is expected to answer in a report next week about the province's energy situation: how to secure clean electricity supplies as existing nuclear plants age and international treaties force a cutback in fossil fuel emissions that contribute to global warming.

There's much speculation that both Ontario and Britain will opt for the same controversial choice: adding new nuclear plants to an electricity generating mix.

Atomic Energy of Canada Ltd., a federal Crown corporation, builds the CANDU nuclear reactor used in Canada. Company officials, in London this week flogging the CANDU, estimate the potential price tag for eight reactors in the U.K. at $16 billion.

Blair got a taste of the battle ahead when two Greenpeace protestors forced him to change the venue for his energy announcement. The protestors managed to climb to the rafters of a London business centre, shower the audience with bits of paper that read, "Nuclear: Wrong Answer," and unfurl banners with the same message.

Blair is widely reported to personally back the nuclear option, but it risks splitting his Labour party and further testing a prime minister weakened by repeated internal revolts.

The review, headed by Energy Minister Malcolm Wicks, will report early next summer. But it already marks a major shift in the government's position.

Only two years ago, a government energy white paper concluded that costs and uncertainty about how to dispose of radioactive waste made nuclear power "an unattractive option."

It urged an increase in renewable energy sources, including wind turbines and tidal waves, as a key way to reduce emissions of "greenhouse gases."

Most scientists believe carbon dioxide emissions are increasing global warming, melting ice caps, raising sea levels and fuelling climate changes that invite ecological and economic disasters.

The white paper also stressed energy efficiency — better insulated buildings and energy-saving appliances, for example — and cutting emissions from vehicles and airplanes, which account for a quarter of Britain's CO{-2} discharges.

Government ministers have struggled to explain what has changed to suddenly put nuclear power back on the policy track. Critics insist it has more to do with the increased lobbying clout of the nuclear industry and Blair's personal backing than anything else.

But dwindling North Sea gas reserves have made Britain an earlier than expected net importer of a resource whose price increased sharply in October.

"Round the world, you can sense feverish rethinking," Blair said this week. "Energy prices have risen. Energy supply is under threat. Climate change is producing a sense of urgency."

At issue are Britain's 12 nuclear power stations — out of an original fleet of 19 — that generate about 23 per cent of the country's electricity. All but three of the 12 stations, most of which are privately owned, will be closed by 2014. The rest are scheduled to shut down by 2035. The closings raise the question of the best, low-carbon-emitting way to fill the looming "electricity gap."

Greenhouse gases are produced during the mining of uranium used to fuel nuclear reactors and the building of nuclear plants. But a nuclear reactor produces virtually no carbon dioxide when it generates electricity.

Most of Britain's electricity comes from burning fuels that contribute to global warming — 38 per cent from gas, 32 per cent from coal and 4 per cent from oil. Only 3 per cent is generated from renewable energy sources, far below the European average of 15 per cent.

Britain has reduced its 1990 level of greenhouse gas emissions by 12.5 per cent, as required by the Kyoto Protocol. It also set itself the goal of reducing carbon dioxide emissions by 20 per cent within 15 years and 60 per cent by 2050.

Blair's government is often criticized for doing little to encourage energy savings or to meet its goal of renewable energy generating 10 per cent of electricity by 2010. Still, experts are divided on whether both methods can fill the gap.

The two most "credible" candidates are nuclear power and a process that blocks carbon emissions by catching and storing them in underground cavities, says Simon Skillings, the British director of strategy and energy policy for E.ON, the second-largest nuclear plant operator in Europe.

The government last summer funded a $52.5 million project that would catch carbon dioxide discharged from fossil fuel power plants and store them under the North Sea, something Norway's Statoil company has been doing since 1996.

E.ON, which does not operate nuclear plants in Britain but is the country's second-biggest power generator, is developing "carbon catching" technology and sees the building of new nuclear plants, under current conditions, as a bad investment, Skillings says.

The Queen switched on the world's first nuclear power station in Britain in 1956. By the time the last station was built 38 years later, the 1986 Chernobyl nuclear accident in Ukraine had largely turned the public off such power.

The nuclear industry's image took a further beating in Britain after it was privatized in 1996. British Energy bought most of the reactors at cut-rate prices but faced bankruptcy when energy prices plummeted. In 2003, the British government saved the company with a $10 billion bailout.

Today, with a 1,000 megawatt nuclear reactor priced at about $2 billion, the government will have to provide a list of guarantees before investors take the plunge, says Keith Parker, chief executive of the Nuclear Industry Association, which represents engineering and energy companies in Britain's nuclear sector.

"Unless there's a clear, long-term energy policy, which the government is very committed to and won't tamper with every few years, then that investment will not be forthcoming," Parker says.

The last nuclear power station built in Britain, Sizewell B, was completed 11 years after a public inquiry began. Design changes to the reactor demanded during the planning and licensing process added $2 billion to its final cost.

The industry wants a fixed time period for planning and public consultations. It also wants "generic" licensing: once a nuclear reactor model has been approved, identical ones automatically benefit from the same permit.

France used the generic licensing process to standardize its industry and create economies of scale for 58 nuclear power reactors that generate almost 80 per cent of its electricity.

Britain's nuclear industry also wants penalties on carbon emissions to stay in place long after the Kyoto Protocol ends in 2012. That would increase the price of electricity generated by fossil fuels and make nuclear power more competitive.

Finally, the government must decide where and how radioactive waste will be disposed, Skillings says.

Cleaning up the radioactive legacy of existing plants will cost at least $117.5 billion, the Nuclear Decommissioning Authority, an independent government body, estimated last summer.

The government will pick up most of the tab. British Energy, which owns eight of the most modern nuclear stations, is contributing to a cleanup fund.

Most of Britain's low-level radioactive waste is stored in concrete vaults at a site in northern England.

It contains about 960,000 cubic metres of the material, enough to fill 384 Olympic-size swimming pools.

Of greater concern is the intermediate and high-level waste, so radioactive that the heat it emits for thousands of years would corrode any container it was placed in.

No country has yet disposed of this waste long term, although most are thinking of burying it deep underground.

It's estimated that if Britain's nuclear reactors all operate to their scheduled shutdown dates and no more are built, Britain's 36,590 cubic metres of intermediate and high-level waste would fill more than 14 Olympic-sized pools.

The waste stockpiles, like the reactors themselves, are prime targets for terrorists, says David Lowry, nuclear issues co-ordinator for SERA, a group in the Labour party that helps shape its environment policy.

"Just think of the psychological impact of a suicidal terrorist striking a nuclear power plant," he says. "It would be a huge event and the public would be absolutely terrified by it.

"On the other hand, I can't image a full-frontal terrorist attack on a windmill," he adds.

A proposal for a wind farm adjacent to the Hinkley Point nuclear site was recently rejected by local authorities, partly after protests from British Energy, Duffy says.

The company likely believes the wind farm would be too close to the site where it hopes a third nuclear station will be built, he adds.

With disputed claims of cancer levels near Hinkley Point higher than the national average, concerns about cracks in the reactor core and the troubling legacy of radioactive waste, Duffy says he can't imagine a government backing new nuclear stations.

But many believe Blair is determined to do exactly that.

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Warning: Manitoba Hydro can't service new 'energy intensive' customers

Manitoba Hydro capacity constraints challenge clean energy growth as industrial demand, hydrogen projects, EV batteries, and electrification strain the grid; limited surplus, renewables, storage, and transmission bottlenecks hinder new high-load connections.

 

Key Points

Limited surplus power blocks new energy-intensive loads until added generation and transmission expand Manitoba's grid.

✅ No firm commitments for new energy-intensive industrial customers

✅ Single large load could consume remaining surplus capacity

✅ New renewables need transmission; gas, nuclear face trade-offs

 

Manitoba Hydro lacks the capacity to provide electricity to any new "energy intensive" industrial customers, the Crown corporation warns in a confidential briefing note that undercuts the idea this province can lure large businesses with an ample supply of clean, green energy, as the need for new power generation looms for the utility.

On July 28, provincial economic development officials unveiled an "energy roadmap" that said Manitoba Hydro must double or triple its generating capacity, as electrical demand could double over the next two decades in order to meet industrial and consumer demand for electricity produced without burning fossil fuels.

Those officials said 18 potential new customers with high energy needs were looking at setting up operations in Manitoba — and warned the province must be careful to choose businesses that provide the greatest economic benefit as well as the lowest environmental impact.

In a briefing note dated Sept. 13, obtained by CBC News, Manitoba Hydro warns it doesn't have enough excess power to hook up any of these new heavy electricity-using customers to the provincial power grid.

There are actually 57 proposals to use large volumes of electricity, Hydro says in the note, including eight projects already in the detailed study phase and nine where the proponents are working on construction agreements.

"Manitoba Hydro is unable to offer firm commitments to prospective customers that may align with Manitoba's energy roadmap and/or provincial economic development objectives," Hydro warns in the note, explaining it is legally obliged to serve all existing customers who need more electricity.

"As such, Manitoba Hydro cannot reserve electric supply for particular projects."

Hydro says in the note its "near-term surplus electricity supply" is so limited amid a Western Canada drought that "a single energy-intensive connection may consume all remaining electrical capacity."

Adding more electrical generating capacity won't be easy, even with new turbine investments underway, and will not happen in time to meet demands from customers looking to set up shop in the province, Hydro warns.

The Crown corporation goes on to say it's grappling with numerous requests from existing and prospective energy-intensive customers, mainly for producing hydrogen, manufacturing electric vehicle batteries and switching from fossil fuels to electricity, such as to use electricity for heat in buildings.

In a statement, Hydro said it wants to ensure Manitobans know the corporation is not running out of power — just the ability to meet the needs of large new customers, and continues to provide clean energy to neighboring provinces today.

"The size of loads looking to come to Manitoba are significantly larger than we typically see, and until additional supply is available, that limits our ability to connect them," Hydro spokesperson Bruce Owen said in a statement.

Adding wind power or battery storage, for example, would require the construction of more transmission lines, and deals such as SaskPower's purchase depend on that interprovincial infrastructure as well.

Natural gas plants are relatively inexpensive to build but do not align with efforts to reduce carbon emissions. Nuclear power plants require at least a decade of lead time to build, and tend to generate local opposition.

Hydro has also ruled out building another hydroelectric dam on the Nelson River, where the Conawapa project was put on hold in 2014.

 

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Germany - A needed nuclear option for climate change

Germany Nuclear Debate Amid Energy Crisis highlights nuclear power vs coal and natural gas, renewables and hydropower limits, carbon emissions, energy security, and baseload reliability during Russia-related supply shocks and winter demand.

 

Key Points

Germany Nuclear Debate Amid Energy Crisis weighs reactor extensions vs coal revival to bolster security, curb emissions.

✅ Coal plants restarted; nuclear shutdown stays on schedule.

✅ Energy security prioritized amid Russian gas supply cuts.

✅ Emissions likely rise despite renewables expansion.

 

Peel away the politics and the passion, the doomsaying and the denialism, and climate change largely boils down to this: energy. To avoid the chances of catastrophic climate change while ensuring the world can continue to grow — especially for poor people who live in chronically energy-starved areas — we’ll need to produce ever more energy from sources that emit little or no greenhouse gases.

It’s that simple — and, of course, that complicated.

Zero-carbon sources of renewable energy like wind and solar have seen tremendous increases in capacity and equally impressive decreases in price in recent years, while the decades-old technology of hydropower is still what the International Energy Agency calls the “forgotten giant of low-carbon electricity.”

And then there’s nuclear power. Viewed strictly through the lens of climate change, nuclear power can claim to be a green dream, even as Europe is losing nuclear power just when it really needs energy most.

Unlike coal or natural gas, nuclear plants do not produce direct carbon dioxide emissions when they generate electricity, and over the past 50 years they’ve reduced CO2 emissions by nearly 60 gigatonnes. Unlike solar or wind, nuclear plants aren’t intermittent, and they require significantly less land area per megawatt produced. Unlike hydropower — which has reached its natural limits in many developed countries, including the US — nuclear plants don’t require environmentally intensive dams.

As accidents at Chernobyl and Fukushima have shown, when nuclear power goes wrong, it can go really wrong. But newer plant designs reduce the risk of such catastrophes, which themselves tend to garner far more attention than the steady stream of deaths from climate change and air pollution linked to the normal operation of conventional power plants.

So you might imagine that those who see climate change as an unparalleled existential threat would cheer the development of new nuclear plants and support the extension of nuclear power already in service.

In practice, however, that’s often not the case, as recent events in Germany underline.

When is a Green not green?
The Russian war in Ukraine has made a mess of global energy markets, but perhaps no country has proven more vulnerable than Germany, reigniting debate over a possible resurgence of nuclear energy in Germany among policymakers.

At the start of the year, Russian exports supplied more than half of Germany’s natural gas, along with significant portions of its oil and coal imports. Since the war began, Russia has severely curtailed the flow of gas to Germany, putting the country in a state of acute energy crisis, with fears growing as next winter looms.

With little natural gas supplies of the country’s own, and its heavily supported renewable sector unable to fully make up the shortfall, German leaders faced a dilemma. To maintain enough gas reserves to get the country through the winter, they could try to put off the closure of Germany’s last three remaining nuclear reactors temporarily, which were scheduled to shutter by the end of 2022 as part of Germany’s post-Fukushima turn against nuclear power, and even restart already closed reactors.

Or they could try to reactivate mothballed coal-fired power plants, and make up some of the electricity deficit with Germany’s still-ample coal reserves.

Based on carbon emissions alone, you’d presumably go for the nuclear option. Coal is by far the dirtiest of fossil fuels, responsible for a fifth of all global greenhouse gas emissions — more than any other single source — as well as a soup of conventional air pollutants. Nuclear power produces none of these.

German legislators saw it differently. Last week, the country’s parliament, with the backing of members of the Green Party in the coalition government, passed emergency legislation to reopen coal-powered plants, as well as further measures to boost the production of renewable energy. There would be no effort to restart closed nuclear power plants, or even consider a U-turn on the nuclear phaseout for the last active reactors.

“The gas storage tanks must be full by winter,” Robert Habeck, Germany’s economy minister and a member of the Green Party, said in June, echoing arguments that nuclear would do little to solve the gas issue for the coming winter.

Partially as a result of that prioritization, Germany — which has already seen carbon emissions rise over the past two years, missing its ambitious emissions targets — will emit even more carbon in 2022.

To be fair, restarting closed nuclear power plants is a far more complex undertaking than lighting up old coal plants. Plant operators had only bought enough uranium to make it to the end of 2022, so nuclear fuel supplies are set to run out regardless.

But that’s also the point. Germany, which views itself as a global leader on climate, is grasping at the most carbon-intensive fuel source in part because it made the decision in 2011 to fully turn its back on nuclear for good at the time, enshrining what had been a planned phase-out into law.

 

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Octopus Energy and Ukraine's DTEK enter Energy Talks

Octopus Energy and DTEK Partnership explores licensing the Kraken platform to rebuild Ukraine's power grid, enabling real-time analytics, smart-home integration, renewable energy orchestration, and distributed resilience amid ongoing attacks on critical energy infrastructure.

 

Key Points

Collaboration to deploy Kraken and renewables to modernize Ukraine's grid with analytics, smart control, and resilience.

✅ Kraken licensing for grid operations and customer analytics

✅ Shift to distributed solar, wind, and smart-home devices

✅ Real-time monitoring to mitigate outages and cyber risks

 

Octopus Energy, a prominent UK energy firm, has begun preliminary conversations with Ukraine's DTEK regarding potential collaboration to refurbish Ukraine's heavily damaged electric infrastructure as ongoing strikes threaten the power grid across the country.

Persistent assaults by Russia on Ukraine's power network, including a five-hour attack on Kyiv's grid, have led to significant electricity shortages in numerous regions.

Octopus Energy, the largest electricity and second-largest gas supplier in the UK, collaborates with energy firms in 17 countries using its Kraken software platform, and Ukraine joined Europe's power grid with unprecedented speed to bolster resilience. This platform is currently being trialled by the Abu Dhabi National Energy Company (Taqa) for power and water customers in the UAE.

A spokesperson from Octopus revealed to The National that the company is "in the early stages of discussions with DTEK to explore potential collaborative opportunities.”

One of the possibilities being considered is licensing Octopus's Kraken technology platform to DTEK, a platform that presently serves 54 million customer accounts globally.

Russian drone and missile attacks, which initially targeted Ukrainian ports and export channels last summer, shifted focus to energy infrastructure by October, ahead of the winter season as authorities worked to protect electricity supply before winter across the country.

These initial talks between Octopus CEO Greg Jackson and DTEK CEO Maxim Timchenko took place at the World Economic Forum in Davos, set against the backdrop of these ongoing challenges.

DTEK, Ukraine's leading private energy provider, might integrate Octopus's advanced Kraken software to manage and optimize data systems ranging from large power plants to smart-home devices, with a growing focus on protecting the grid against emerging threats.

Kraken is described by Octopus as a comprehensive technology platform that supports the entire energy supply chain, from generation to billing. It enables detailed analytics, real-time monitoring, and control of energy devices like heat pumps and electric vehicles, underscoring the need to counter cyber weapons that can disrupt power grids as systems become more connected.

Octopus Energy, with its focus on renewable sources, can also assist Ukraine in transitioning its power infrastructure from centralized coal-fired power stations, which are vulnerable targets, to a more distributed network of smaller solar and wind projects.

DTEK, serving approximately 3.5 million customers in the Kyiv, Donetsk, and Dnipro regions, is already engaged in renewable initiatives. The company constructed a wind farm in southern Ukraine within nine months last year and has plans for additional projects in Italy and Croatia.

Emphasizing the importance of rebuilding Ukraine's economy, Timchenko recently expressed at Davos the need for Ukrainian and international companies to work together to create a sustainable future for Ukraine, noting that incidents such as Russian hackers accessed U.S. control rooms highlight the urgency.

 

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US power coalition demands action to deal with Coronavirus

Renewable Energy Tax Incentive Extensions urged by US trade groups to offset COVID-19 supply chain delays, tax equity shortages, and financing risks, enabling direct pay, PTC and ITC qualification, and standalone energy storage credits.

 

Key Points

Policy measures that extend and monetize clean energy credits to counter COVID-19 disruptions and financing shortfalls.

✅ Extend start construction and safe harbor deadlines

✅ Enable direct pay to offset reduced tax equity

✅ Add a standalone energy storage credit

 

Renewable energy and other trade bodies in the US are calling on Capitol Hill to extend provision of tax incentives to help the sector “surmount the impacts” of the COVID-19 crisis facing clean energy.

In a signed joint letter, the American Council on Renewable Energy (ACORE), American Wind Energy Association (AWEA), Energy Storage Association (ESA), National Hydropower Association (NHA), Renewable Energy Buyers Alliance (REBA), and the Solar Energy Industries Association (SEIA) stated: “With over $50bn in annual investment over each of the past five years, the clean energy sector is one of the nation’s most important economic drivers. But that growth is placed at risk by a range of COVID-19 related impacts”.

These include “supply chain disruptions that have the potential to delay utility solar construction timetables and undermine the ability of wind, solar and hydropower developers to qualify for time-sensitive tax credits, and a sudden reduction in the availability of tax equity, which is crucial to monetising tax credits and financing clean energy projects of all types.”
The letter goes onto state: “Like all sectors of our economy the renewable and clean grid industry – including developers, manufacturers, construction workers, electric utilities, investors and major corporate consumers of renewable power – needs stability.

“The current uncertainty about the ability to qualify for and monetise tax incentives will have real and substantial negative impacts to the entire economy.

On behalf of the thousands of companies that participate in America’s renewable and clean energy economy, the coalition of organisations is requesting the US Government, echoing Senate calls to support clean energy, take three “critical” steps to address pandemic-related disruptions.

The first is an extension of start construction and safe harbour deadlines to ensure that renewable projects can qualify for renewable tax credits amid the Solar ITC extension debate and despite delays associated with supply chain disruptions.

The second is the implementation of provisions that will allow renewable tax credits to be available for direct pay to facilitate their monetisation, supporting U.S. solar and wind growth in the face of reduced availability of tax equity.

Thirdly, the signatories have requested the enactment of a direct pay tax credit for standalone energy storage to foster renewable growth as the industry sets sights on market majority and help secure a more resilient grid.

 

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Cost, safety drive line-burying decisions at Tucson Electric Power

TEP Undergrounding Policy prioritizes selective underground power lines to manage wildfire risk, engineering costs, and ratepayer impacts, balancing transmission and distribution reliability with right-of-way, safety, and vegetation management per Arizona regulators.

 

Key Points

A selective TEP approach to bury lines where safety, engineering, and cost justify undergrounding.

✅ Selective undergrounding for feeders near substations

✅ Balances wildfire mitigation, reliability, and ratepayer costs

✅ Follows ACC rules, BLM and USFS vegetation management

 

Though wildfires in California caused by power lines have prompted calls for more underground lines, Tucson Electric Power Co. plans to keep to its policy of burying lines selectively for safety.

Like many other utilities, TEP typically doesn’t install its long-range, high-voltage transmission lines, such as the TransWest Express project, and distribution equipment underground because of higher costs that would be passed on to ratepayers, TEP spokesman Joe Barrios said.

But the company will sometimes bury lower-voltage lines and equipment where it is cost-effective or needed for safety as utilities adapt to climate change across North America, or if customers or developers are willing to pay the higher installation costs

Underground installations generally include additional engineering expenses, right-of-way acquisition for projects like the New England Clean Power Link in other regions, and added labor and materials, Barrios said.

“This practice avoids passing along unnecessary costs to customers through their rates, so that all customers are not asked to subsidize a discretionary expenditure that primarily benefits residents or property owners in one small area of our service territory,” he said, adding that the Arizona Corporation Commission has supported the company’s policy.

Even so, TEP will place equipment underground in some circumstances if engineering or safety concerns, including electrical safety tips that utilities promote during storm season, justify the additional cost of underground installation, Barrios said.

In fact, lower-voltage “feeder” lines emerging from distribution substations are typically installed underground until the lines reach a point where they can be safely brought above ground, he added.

While in California PG&E has shut off power during windy weather to avoid wildfires in forested areas traversed by its power lines after events like the Drum Fire last June, TEP doesn’t face the same kind of wildfire risk, Barrios said.

Most of TEP’s 5,000 miles of transmission and distribution lines aren’t located in heavily forested areas that would raise fire concerns, though large urban systems have seen outages after station fires in Los Angeles, he said.

However, TEP has an active program of monitoring transmission lines and trimming vegetation to maintain a fire-safety buffer zone and address risks from vandalism such as copper theft where applicable, in compliance with federal regulations and in cooperation with the U.S. Bureau of Land Management and the U.S. Forest Service.

 

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Share of coal in UK's electricity system falls to record lows

UK Coal Phase-Out marks record-low coal generation as the UK grid shifts to renewable power, wind farms, and a net zero trajectory, slashing carbon emissions and supporting cleaner EV charging across the electricity system.

 

Key Points

UK Coal Phase-Out ends coal-fired electricity nationwide, powered by renewables and net zero policy to cut grid carbon.

✅ Coal's Q2 share fell to 0.7%, a record low

✅ Renewables up 12% with Beatrice wind farm

✅ EV charging grows cleaner as grid decarbonizes

 

The share of coal in the UK’s electricity system has fallen to record lows in recent months, alongside a coal-free power record, according to government data.

The figures show electricity generated by the UK’s most polluting power plants made up an average of 0.7% of the total in the second quarter of this year, a shift underway since wind first outpaced coal in 2016 across the UK. The amount of coal used to power the electricity grid fell by almost two-thirds compared with the same months last year.

A government spokesperson said coal-generated energy “will soon be a distant memory” as the UK moves towards becoming a net zero emissions economy, despite signs that low-carbon generation stalled in 2019 in some analyses.

“This new record low is a result of our world-leading low-carbon energy industry, which provided more than half of our energy last year and continues to go from strength to strength as we aim to end our contribution to climate change entirely by 2050,” the spokesperson said.

The UK electricity market is on track to end coal power after 142 years by the government’s target date of 2025.

This year three major energy companies have announced plans to close coal-fired power plants in the UK, which would leave only four remaining after the coming winter, ahead of the last coal power station going offline nationwide.

RWE said this month it would close the Aberthaw B power station in south Wales, its last UK coal plant, after the winter. SSE will close the Fiddler’s Ferry plant near Warrington, Cheshire, in March 2020, and EDF Energy will shutter the Cottam coal plant in September.

So far this year the UK has gone more than 3,000 hours without using coal for power, including a full week without coal earlier in the year – nearly five times more than the whole of 2017.

Meanwhile, the government’s data shows that renewable energy climbed by 12% from the second quarter of last year, boosted by the startup of the Beatrice windfarm in the Moray Firth in Scotland, and the UK leading the G20 in wind power share in recent assessments.

The cleaner power system could accelerate carbon savings from the UK’s roads, too, as more drivers opt for electric vehicles. A study by Imperial College London for the energy company Drax found that the UK’s increasingly low-carbon energy system meant electric cars were a greener option even when taking into account the carbon emissions produced by making car batteries.

Dr Iain Staffell, of Imperial College London, said: “An electric vehicle in the UK simply cannot be more polluting than its petrol or diesel equivalent – even when taking into account the upfront carbon cost of manufacturing their batteries. Any EV bought today could be emitting just a tenth of what a petrol car would in as little as five years’ time, as the electricity it uses to charge comes from an increasingly low-carbon mix.”

 

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