Glengorm the biggest UK gas find since Culzean, Woodmac says

Chinese energy firm Cnooc’s discovery at Glengorm is the largest gas find in the UK since Culzean in 2008, an analyst has said.

Kevin Swann, senior analyst at Wood Mackenzie, said: “There is a lot of hype around frontier areas like west of Shetland, where Total discovered the Glendronach field last year.

“But Glengorm is in the central North Sea and this find shows there is still life in some of the more mature UK waters.”

He added: “This was third time lucky for Cnooc at Glengorm. Technical problems saw it try and fail to drill the prospect twice in 2017, so persistence has paid off.

“This is a good start to what could prove to be a pivotal year for UK exploration with several high impact wells in the plan.”

Glengorm continues a spectacular run of high-impact exploration success for both Cnooc and Total, ranked fifth and third in the world respectively, by exploration volumes discovered in 2018.

Andrew Latham, vice president for global exploration, at Woodmac, said: “Cnooc is a 25% partner in the prolific Stabroek Block in Guyana, where 5 billion boe has been found since 2015.

“It has also found over 1.5 billion boe offshore China since 2017.”

He added: “Total has reset its exploration strategy under new leadership since 2015 and it is now seeing much improved results.

“Over the past year, Total operated the large Glendronach gas discovery in the UK west of Shetland and is a partner in the giant Calypso gas discovery, offshore Cyprus, as well as the Ballymore find, a major oil discovery in the US Gulf of Mexico.

“Through its 20% equity in Novatek, Total also holds an indirect stake in the North Obskoye gas find, offshore Russia, the world’s largest discovery in 2018 with reserves of over 11 trillion cubic feet.”

Mr Latham said: “Exploration industry returns averaging 13% in 2018 were the highest in over a decade, driven by lower costs and a focus on drilling prospects with a straightforward route to commercialisation in the event of success. Glengorm fits this revitalised exploration model perfectly. It looks to be a valuable discovery that should help sustain the industry’s profitability into 2019.”


Britain, Brexit, nuclear power and EU energy

The decision to postpone constructing a new nuclear plant in Wales has left a hole in the UK’s post-Brexit, low carbon energy plans.

The decision by Japanese firm Hitachi this month to postpone the Wyfla nuclear power station development in Anglesey, as well as its Oldbury project near Bristol, leaves a substantial gap in future low carbon electricity supply for the UK.

Work has started on Hinkley Point in Somerset, but this is the only one of the six major nuclear projects in the pipeline to progress. Last year Toshiba, another Japanese company, pulled out of developing a power plant at Moorside in Cumbria.

The proposed developments by Chinese firm CGN at Sizewell (Suffolk) and Bradwell (Essex) are politically contentious and yet to be agreed.

More renewables

In 2008, the Labour government set out its strategic vision for a future UK low carbon power sector, which had nuclear at its centre. But in the 20 years since, the economics of nuclear have deteriorated, while the remarkable drop in the cost of renewables and flexible energy sources is threatening the profitability of large, inflexible power stations.

There are currently four high-voltage electricity interconnectors that connect Britain to the Netherlands (BritNed), France (IFA), and the island of Ireland (Moyle and EWIC). A fifth connection, running to Belgium (Nemo), is due to go live at the end of January.

At least another eight are planned to be developed by the late 2020s, nearly trebling the supply capacity that currently exists.

Interconnectors are important for energy and climate change for several reasons. They help decarbonise UK electricity consumption by importing lower carbon power from countries such as France which has lots of nuclear power, and – in future – Norway and Iceland which generate electricity from hydro and geothermal.

They also contribute to decarbonisation by helping to match supply and demand, which in turn allows more renewables and electric vehicles.

Negative consequences

Excess electricity can then be exported during periods of low demand or imported when demand is high – something that helps with security of electricity supply, as imports can complement domestic power generation.

Interconnectors also help reduce electricity prices. The UK has higher wholesale power prices than other EU countries, meaning electricity typically flows to the UK from markets where power is less expensive. Buying this cheaper electricity lowers prices here, which reduces consumer bills.

Even though the current and previous governments have actively encouraged the building of interconnectors, the UK leaving the EU threatens their development and operation.

After Brexit the UK is expected to leave the EU’s internal energy market, as well as key EU market arrangements and trading platforms. These allow electricity trade to happen in the most efficient and cost-effective way and losing access to them could lead to higher bills for consumers.

This would also reduce the system benefits of developing interconnectors as they cannot work at their most effective, which in turn would have negative consequences for future development of renewables. But irrespective of the outcome of Brexit, the UK should build more interconnection as it is a ‘no-regrets’ option for the UK.


Even after leaving the EU, they can still needed to help with the transition to a low carbon energy system, the least-cost pathway to decarbonisation, and fill the capacity gap from the postponed nuclear plants.

The UK and EU will need to continue cooperating on climate change and energy issues post Brexit, because the connected physical space between them means that choices made by one will impact the other.

As the Brexit negotiations move towards discussions on the future relationship, the UK should prioritise interconnectors in discussion on future cooperation and commit to cross-border initiatives in energy markets around the North Sea region.

The rationale to build interconnectors and their contribution to energy and tackling climate change has long been recognised, but there is now an even greater need to construct them.

Despite Brexit, the UK government needs to bolster its support for new interconnectors and maintain high levels of cooperation with the EU and regional partners to ensure they get built and the UK stays on the path to decarbonisation.


Electricity replacement projects reduce carbon dioxide emission

HANGZHOU, Jan. 24 (Xinhua) — East China’s Zhejiang Province launched over 3,700 “electricity replacement projects” in 2018, leading to a sharp reduction of carbon dioxide emission, the State Grid Zhejiang Electric Power Co. Ltd. said Thursday.

A total of 3,714 replacement projects were launched in the province last year, which resulted in the consumption of over 7 billion kilowatt hours of electricity to reduce the consumption of coal and oil equivalent to 2.8 million tons of standard coal, the company said.

The company has been promoting electric power in major fields over the past few years, instead of using coal and oil, so as to slash air pollution and haze.

The major fields cover transportation, residential consumption and industries including tourism, manufacturing industry and agriculture.

So far, 71 tourist attractions in Zhejiang rely entirely on electricity for energy supply. More than 25,000 households in the province have used electricity for heating.


Community energy: a local solution?

Over the years there have been many grass-roots community energy projects in the UK and elsewhere, often with an emphasis on local ownership. This provides an economic reward and incentive for investing in local projects and the opportunity for direct local control as well as wider local economic, social and environmental benefits. Local ownership has also helped to avoid opposition at the local level to wind farms elsewhere, as is evident from Denmark, where most wind projects are locally-owned and usually welcomed and, indeed, sought after. As the Danes say, “your own pigs don’t smell”.

There are, of course, a range of factors shaping how easy it is to move to local ownership, including the availability of suitable support schemes and local orientations. Although there are many constraints, there are also opportunities, and across the EU there are many community energy projects.

Some of these involve local ownership. In addition to the wind co-ops in Denmark, nearly 40% of German renewable capacity is now locally owned, some by household domestic photovoltaic (PV) “prosumers”, some by local co-ops, with many hundreds of village and town-based schemes in place. Some see this as prefiguring a new form of decentralized socio-economic power, with local social entrepreneurship challenging the existing energy market system. Certainly, in some countries, local ownership and self-generation mean that the existing power utilities are losing control of some parts of their market and local ownership clearly opens up a wide range of technical, social and political issues.

Community capacity

The situation in the UK, however, is not quite so dramatic. There is maybe nearly 4 GW of FiT-backed small, privately-owned “prosumer” PV. But in terms of community ownership, although local energy projects have involved a lot of people in local activism and networking — 48,000 according to a recent “State of the Sector” report — in all, there is only around 249 MW of locally-owned/community project capacity so far.

What’s more, the prognosis for the future is mixed. The second edition of the “State of the Sector” review by Community Energy England and Community Energy Wales notes that, while there was 168 MW of locally-owned project capacity in England, Wales and Northern Ireland, only one new community organization was constituted in 2017, with 30 fewer successful projects and 31% less generation capacity installed or acquired than in 2016. The cuts to the Feed-In Tariff (FiT) were a major problem.

The UK government has only made limited commitment to local projects, following the publication of DECC’s Community Energy Strategy report in 2104. The situation in Scotland is better, given its more supportive government, with 666 MW of local power in place. Following the early attainment of the Scottish Government’s 500 MW target for community and locally-owned energy in 2017, Scotland, which has a Community & Renewables Energy Scheme (CARES), set an increased target of 1 GW by 2020. And it seems to be well on the way to reaching that. Although only 81 MW of the 666 MW of local power capacity in place so far was community-owned, it did represent a 12% increase in community-owned renewables capacity between 2016 and 2017 across more than 500 separate installations.

With ideas for smart-grid demand management in development, it could be that local energy projects will at long last come into their own

Dave Elliott

However, while CARES has clearly helped in Scotland, the Feed-Tariff has been a key element in all of this, and with that cut back and soon to go entirely, the prognosis does not look good. The State of the Sector review noted that: “At present it seems likely that the slowdown in the sector will continue into 2018. Despite ongoing innovation, the greater risks and hurdles associated with such projects mean that the number of financially viable projects in 2017 has been low. Communities are calling for better support for renewable energy projects, as well as reduced barriers to project development. Critically, clearer and more supportive government strategy is required, with greater support at the regional and local levels from local authorities.”

External support

The point is that, while self-help is important, there is also a need for external assistance. The State of the Sector review said, “improved policy support must be offered throughout the sector to improve project margins and viability and realize the benefits of local low-carbon projects. Whether through financial interventions — including reviewed subsidies, investment incentives, innovative support and early stage funding — or through greater engagement with the community energy sector (e.g. local authority partnerships), the public sector must play a central role in enabling community energy. Improved strategies and support will allow communities to continue to develop their low-carbon ideas to the benefit of local people and areas, whether through traditional routes or by establishing more innovative paths towards low-carbon community development”.

Nevertheless, looking to the future, the sector review concluded on a hopeful note: “An increasing focus on new business models, including behind-the-meter renewables, direct or local energy supply and a more collaborative approach to community energy, is driving forward a new agenda in the community energy sector”. That might include branching out from power generation via PV solar, which has been the main focus so far. There have also been 1.9 MW of local heat-supply projects and many energy efficiency/demand management projects. With ideas for smart-grid demand management in development, it could be that local energy projects will at long last come into their own. That’s what seems to be happening in some places in Germany, with attempts to move into distribution as well as generation, in some cases via municipal schemes.

In the UK context, some local councils have been exploring local power project options, developing out of the pioneering schemes in place in Nottingham and Bristol and that idea is part of the Labour party’s proposals for “public power”, with municipal projects running alongside community energy co-operatives. The prescription of local cooperative/community ownership does assume there would be demand for this form of involvement. That may not be the case. Most people may be happy just to buy whatever power is offered. Certainly, few people, wherever they lived, have in the past shown much interest in where their energy came from. However, issues relating to the costs, as well as the health and environmental impacts of power generation, as currently organized, have led to political pressures for change, with co-operatives and local ownership, along with other forms of democratic control, being one approach.

The loss of the FiT may make it harder for local projects of any kind to get going but, as I noted in my last post, the government is now proposing a “Smart Export Guarantee” as a replacement for the FiT export tariff, creating a local market for excess electricity. That might help community energy projects. But it’s still some way off, and not everyone will welcome the replacement of the FiT with a competitive market. The proposed new system is based on the power utilities, who run the trades and set the market prices, not on “peer to peer” transactions between prosumers, which some see as a potentially more progressive way ahead, possibly expanded to include community groups.


North Sea rocks could act as large-scale underwater renewable energy stores, study finds

Rocks at the bottom of the North Sea may provide the perfect storage location for renewable energy, according to a new study.

Excess power could be stored in the form of compressed air inside porous formations on the seabed, providing a reservoir that can provide energy on demand.

This pressurised air can be released to drive a turbine, generating a large amount of electricity.

This would allow green energy to be stored in summer and released in winter, when demand is highest.

Along with battery storage and connections linking Britain’s power supply to other European nations, experts hope compressed air energy storage will provide the UK with a constant supply of green energy.

After the Japanese firm Hitachi announced it was withdrawing support for a major nuclear plant, there was speculation about how the government will fill the energy gap left by failed nuclear plans.

Environmental groups say the shortfall can be made up by investing in renewable energy – particularly wind power.

However, critics say the erratic nature of wind and solar energy will not be able to provide the constant supply required to power Britain’s grid.

Building devices that can store green energy for when the wind is not blowing or the sun is not shining would allow the UK to keep the lights on without relying on climate-harming fossil fuels.

In their new analysis, scientists from the universities of Edinburgh and Strathclyde suggested drilling deep wells into North Sea rocks would create sites at which large quantities of air could be injected into sandstone pores.

In their study they used mathematical models to assess the potential of this technique in British waters.

They found geological formations in the North Sea have the potential to store one and a half times the UK’s electricity needs for the months of January and February.

“This method could make it possible to store renewable energy produced in the summer for those chilly winter nights,” said Dr Julien Mouli-Castillo from the University of Edinburgh.

“It can provide a viable, though expensive, option to ensure the UK’s renewable electricity supply is resilient between seasons. More research could help to refine the process and bring costs down.”

One way to save money and make the entire process more efficient would be to place the underwater wells close to large-scale offshore wind projects so energy could be funnelled straight down into the rock.

A similar process in which compressed air is stored in deep salt caverns is already being used at sites in the US and Germany.

These results were published in the journal Nature Energy.


Q&A: Can the UK meet its climate goals without the Wylfa nuclear plant?

The Japanese firm Hitachi has shelved a planned new nuclear plant at the Wylfa site on Anglesey in Wales, leaving a large hole in the UK government’s climate and energy strategy.

The news comes just months after the planned Moorside plant in Cumbria was scrapped by Toshiba, another Japanese conglomerate. Hitachi’s UK subsidiary, Horizon, has also suspended work on a third new nuclear scheme at Oldbury in Gloucestershire.

New nuclear plants were due to replace old reactors as they retire through the 2020s, helping to plug the gap left by coal-fired power stations being phased by 2025. They form a key part of the government’s plans to “keep the lights on” while meeting the UK’s legally binding climate goals.

However, recent analysis from the government’s official advisers the Committee on Climate Change (CCC) shows the UK could meet its power demand and climate goals to 2030 at low cost, without any new nuclear beyond the Hinkley C scheme already being built in Somerset.

This new analysis reflects the dramatic cost reductions seen for renewables in recent years. Greg Clark, the UK’s secretary of state for business, energy and industrial strategy (BEIS), made a similar point last week as he spoke in parliament about the failed Wylfa deal. He told MPs:

“The economics of the energy market have changed significantly in recent years. The cost of renewable technologies such as offshore wind has fallen dramatically…The challenge of financing new nuclear is one of falling costs and greater abundance of alternative technologies, which means that nuclear is being outcompeted.”

The outlook to 2050 is much less certain and, for Clark, nuclear will continue to have an “important role” in the future UK energy mix.

Modelling from the Energy Technologies Institute and Imperial College Londonsuggests new nuclear would help to keep costs down as the UK approaches zero emissions. Work by Aurora Energy Research finds that a highly renewable energy system in 2050, with no new nuclear added after Hinkley C, might have similar overall costs as a high nuclear pathway.

In this in-depth Q&A, Carbon Brief looks at what the Wylfa news means for the UK’s climate goals and what role nuclear might play in future.

What has happened?

The Japanese conglomerate Hitachi has shelved the planned new nuclear plant at Wylfaon Anglesey in Wales. The 2.9 gigawatt (GW) dual-reactor project would have cost a reported £20bn, according to the Financial Times, while others say it would have cost £16bn. [The difference is likely due to whether the figure includes financing costs or not.]

Hitachi will write off £2.1bn already put towards the project. Its UK subsidiary Horizonhas also suspended work on the 2.9GW Oldbury new nuclear plant in Gloucestershire, BBC News says.

The news follows Toshiba’s decision, in November 2018, to wind up its NuGen subsidiary in the UK. NuGen was to have built the 3.3GW Moorside new nuclear plant in Cumbria.

The door remains open to Hitachi resurrecting the schemes, but according to the Japanese newspaper Asahi Shimbun: “Analysts and investors viewed the suspension as an effective withdrawal.”

Why does it matter?

Together, the three planned plants at Wylfa, Moorside and Oldbury would have had a combined capacity of 9.1GW and generated 72 terawatt hours (TWh) of near-zero carbon power per year. This is roughly what the UK’s existing nuclear fleet produces, generating around a fifth of the country’s electricity last year.

Generating this amount of electricity with gas would lead to emissions of roughly 29 million tonnes of CO2 each year (MtCO2), around 8% of overall UK emissions in 2017. This level of emissions would be even more significant in the context of shrinking UK carbon budgets.

There are eight nuclear power stations operating in the UK today, with a total capacity of 8.9GW. With the exception of Sizewell C in Suffolk, these were all built in the 1970s and 1980s.

These older reactors are due to retire during the 2020s and are shown in shades of grey in the chart, below. Sizewell C (black) was built in 1995 and is due to retire in 2035, though operator EDF wants to extend its life by as much as 20 years until 2055.

Some six new nuclear plants had been under development around the UK, totalling 18GW (coloured chunks in the chart). The Hitachi news means three have now been shelved (red).


The government has also pledged to phase out by 2025 the UK’s six remaining large coal plants, totalling nearly 11GW. These continue to play an important role during periods of peak demand, but operate for relatively few hours across the year and generated 17TWh in 2018 (5% of the UK total).

New nuclear formed a key part of government plans to replace retiring reactors and coal. BEIS has some 7GW of new nuclear being built by 2030 in its latest energy and emissions projections. This is equivalent to Hinkley C in Somerset, plus at least three additional reactors at one or more sites.

Published a year ago, these projections scaled back the pace of nuclear new build compared to earlier outlooks, but, nevertheless, included steady growth throughout the 2020s and beyond.

Can the UK still meet its climate goals?

The sheer scale of the now-shelved nuclear schemes leaves a large hole in UK climate plans. But legally binding carbon budgets to 2030 could still be met without any additional new nuclear plants, according to analysis from the CCC.

Last year, the CCC published updated scenarios for the power sector through to 2030. These plot a range of pathways to meeting the UK’s 2030 climate goals, only some of which add new nuclear beyond the Hinkley C plant that is already being built in Somerset.

The chart below compares nuclear’s contribution to UK generation in 2018 (red chunk, left-hand column) with a range of scenarios for 2030 (remaining columns). Each scenario limits power sector carbon intensity in 2030 to 100 grammes of CO2 per kilowatt hour (gCO2/kWh) or below.

The CCC’s “central renewables” and “high renewables” scenarios meet the 2030 carbon target without new nuclear beyond Hinkley C. In these scenarios, nuclear generation in 2030 is 35TWh – the estimated output of Hinkley C plus Sizewell B, each running for 90% of available hours.


Note that each of the 2030 scenarios supplies enough electricity to meet projected demand, meaning the lights would not “go out”. Gas would still supply 20-25% of electricity, most of which would be used to cover peak demand during winter or to fill gaps in variable renewable output.

The CCC scenarios out to 2030 all massively expand renewables, whether or not additional new nuclear plants get built. The renewable share of the mix increases from 33% in 2018 to at least 58% in 2030. Nuclear’s share falls from 18% in 2018 to between 10% and 17% in 2030. At the low end, where no new nuclear is added after Hinkley C, it is renewables that make up the gap.

[The CCC says: “We do not consider [the BEIS 2030] pathway credible.” This pathway sees nuclear’s share hold steady, though, as BEIS notes, this is “not based on [nuclear] developers’ proposed pipeline”. BEIS also assumes imports via electricity interconnectors reach 21% of the total while the CCC assumes net-zero imports, with interconnectors helping balance supply and demand.]

The CCC says expanding wind and solar is a “low-regrets” option as renewables are likely to be cheaper than new gas, with similar costs to running existing gas plants or raising imports, even after accounting for the costs of integrating their variable output onto the grid. The CCC adds:

“If new nuclear projects [beyond Hinkley C] were not to come forward, it is likely that renewables would be able to be deployed on shorter timescales and at lower cost.”

Replacing the output of the shelved new nuclear plants at Wylfa, Moorside and Oldbury with renewables would be 13-33% cheaper, including the costs of balancing variable output, according to quickfire analysis from the Energy and Climate Intelligence Unit.

Note that reductions in per-capita electricity generation have saved the UK the equivalent of four Hinkley Cs of demand since 2005, according to recent Carbon Brief analysis. The CCC assumes continued efficiency improvements to 2030 are offset by demand for electric vehicles and heating.

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What about the UK’s 2050 target?

The route to meeting the UK’s climate goals in 2030 is relatively clear, with or without the likes of the Wylfa new nuclear plant. Looking out to 2050, however, the path becomes much more uncertain – not least because the UK is set to raise its targets in line with the Paris Agreement.

Other reasons for caution around longer-term pathways include fundamental uncertainty about the future, the need for extra electricity to help decarbonise heat and transport, and an expectation of rising costs to integrate variable renewables as their share grows beyond 50 or 60%.

As Clark told MPs:

“The government continue to believe that a diversity of energy sources is the best way of delivering secure supply at the lowest cost and that nuclear has an important role to play in our future energy mix…Having a substantial mix of technologies has an insurance quality. We should recognise that, but there is a limit to what we can pay for the benefit, which is reflected in my statement.”

Several recent analyses have investigated the UK’s electricity mix to 2050, in light of these challenges, uncertainties and the recent renewable cost reductions.

First, there is the modelling from the Energy Technologies Institute (ETI) published in late 2018. This suggests the least-cost path to 2050 includes 7GW of new nuclear by 2030 and 21GW by 2050.

The ETI notes this may not be “realistic”, but still emphasises the need for “low carbon baseload capacity [such as nuclear or CCS] to complement renewable generation”. It adds: “The scale of the requirement will depend on progress in developing storage and demand side flexibility.”

Second, there is the modelling for the CCC carried out by Imperial College London and published in summer 2018. This includes the option to balance seasonal variations in renewable output using “power-to-gas”, where electricity is used to make hydrogen that can be stored for later use.

This modelling suggests nuclear’s role in the future energy mix could be replaced using power-to-gas, with stored hydrogen being used to fill the gaps in variable renewable power output. However, Imperial says this would be around 10% more expensive than a 2050 scenario including nuclear or another source of “firm low-carbon capacity”, meaning one that can be turned on at will.

Aurora’s work includes hourly balancing of modelled supply and demand. It formed the basis for the NIC recommendation that the UK contract for no more than one extra nuclear plant before 2025, in addition to the Hinkley C scheme.

However, its findings come with a number of caveats. The most important is that the modelling assumes a highly flexible electricity system, with plenty of interconnectors to other countries, smart charging of electric vehicles, demand-side response and batteries. Aurora explains:

“In a flexible system, reaching 70-80% renewable production by 2050 is the cost-optimising option, with no new nuclear beyond Hinkley Point C needed to meet carbon targets. In a less flexible system, more than 40% renewable production by 2050 increases the cost to consumers.”

Aurora also cautions that a 90% renewable mix “may be more vulnerable to extreme winter system stress events”. For example, a prolonged windless cold snap. [The “Beast from the East” in March 2018 was cold, but windy.] Such a system would be reliant on imports during stress events, but supplies could also be tight in exporting countries, due to internationally correlated weather.

Another point to note with the Aurora modelling is that it allows for net electricity imports to the UK in 2050, whereas the CCC assumes demand is met purely from domestic resources.

This spring, the CCC will publish its advice on raising the UK’s long-term climate goals in line with Paris. This advice is expected to include pathways to reaching the higher targets.

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How has the media responded?

The news of Hitachi’s Wylfa decision sparked a series of newspaper editorials and opinion pieces.

“New nuclear plants may not be worth the cost,” says the Financial Times leader, adding that the decision “all but sounds the death knell for the UK’s 2013 energy strategy”. It says:

“Hitachi’s decision…should prompt the government to re-examine whether nuclear power is needed and if so whether the inevitable cost to taxpayers is justifiable. A comprehensive, independent and strategic review of energy policy should establish whether the case for nuclear power – based on the intermittency of renewables and the need for a zero carbon base load – survives these recent project failures.”

The FT says this review should also consider the falling cost of renewables and should look for “better incentives”. It adds that more direct government investment in new nuclear might be a “sensible” alternative to Chinese funding, given “legitimate security concerns”.

For the Times editorial, the news leaves the UK with a “headache”. It adds: “Pressing ahead without new nuclear capacity is plausible, but not without a considerable expansion of renewable energy and its storage capabilities.”

The Guardian editorial says current UK energy policies “don’t add up”. It says: “The challenge for all those in the UK who see this as good rather than inconvenient news – because cheap, green energy that doesn’t create toxic waste is what the planet needs – is to explain how demand will be met when existing nuclear power stations have been wound down, at times when there is no sun or wind, until we have the technology we need to store electricity.”

The Daily Mail editorial calls the Wylfa news “deeply worrying”, noting nuclear plants supply a fifth of UK electricity, yet will mostly retire by 2025. “With coal being phased out, no new gas-fired stations under way and fracking unpopular, how on earth will [government] fill this vast energy shortfall,” it asks, saying the UK could become “dangerously dependent” on nuclear built by China or gas from Russia. [The UK currently gets much less than 1% of its gas directly from Russia.]

The Observer editorial says the news leaves the UK’s energy policy “in ruins”. It says: “The nation needs to know, very quickly, how ministers intend to make up for this lost capacity.” Despite higher costs than renewables, the Observer says: “[Government] need[s] to reopen talks with Hitachi and Toshiba to hammer out a sensible electricity pricing mechanism for power from their plants and so allow building work to resume.” It also calls for more investment in renewables and CCS.

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Is there another way to fund new nuclear?

The Wylfa deal collapsed despite a “significant and generous” package of support being offered by government, according to Clark. In a sign of the lack of investor appetite for the deal, Hitachi’s shares jumped 13% on news the project was being shelved, according to Reuters.

The package on offer included a fixed price of up to £75 per megawatt hour (MWh) for Wylfa’s electricity under the Contracts for Difference (CfD) scheme for low-carbon power. It also included the government taking a one-third stake in the project and providing all necessary debt finance.

The key problem with the deal appears to have been the fact that Hitachi would have assumed essentially all of the risk related to building the Wylfa plant on time and to budget. It would not have received any payments until the plant started to operate. Indeed, this was a central selling point of the CfD deal secured for Hinkley C, according to then-secretary of state Ed Davey.

[Some commentators have argued that government preoccupation with Brexit is also putting off potential investors, with Nick Butler in the Financial Times writing: “International business has begun to distrust the UK as a place to invest.”]

In 2017, the National Audit Office (NAO) criticised the Hinkley deal and argued that government taking on a share of construction risk could have resulted in a lower price for consumers:

“Alternative financing models would have exposed consumers and/or taxpayers to the risks of the project running over budget…But our analysis suggests alternative approaches could have reduced the total project cost. The department did not assess whether the reduced cost balanced against the increased exposure to risk would have resulted in better value for money for electricity consumers.”

The NAO’s report explored alternative financing models, including versions of a “regulated asset base” deal (RAB). This model is already used to finance major infrastructure projects, including electricity transmission lines or London’s “supersewer” under the Thames.

Put simply, RAB would see the owners of a new asset (the new nuclear plant) being paid a regulated return on their investment. Crucially, payments would begin during the construction phase of the project, whereas CfDs only start once electricity is being generated.

The government has been exploring RAB for new nuclear since mid-2018 and has the chief financial officer of the supersewer advising it on the matter. The idea has prominent supporters, including Prof Dieter Helm, author of a recent report for government on the costs of energy.

Two new nuclear reactors at the Vogtle plant in Georgia, US, are being built under a RAB. However, the project has been in financial difficulty as a result of cost overrunsand delays.

Interestingly, the then-Department of Energy and Climate Change (DECC) considered, but rejected a RAB model for new nuclear in 2011. At the time, DECC said the idea would “transfer construction risk, which generators are better suited to manage, to the consumer” and called it “high risk”.




Record numbers switched energy provider last year amid price hikes

A record number of people switched energy supplier last year as consumers were hit with the highest number of price hikes in recent history.

However, the energy industry warned that progress risked being undermined by fewer people shifting because of the government’s price cap.

A total of 5.8m households moved to another electricity supplier in 2018, up 6% on 2017, according to Energy UK.

The trade body hailed the figures as a sign consumers are highly engaged in the market, but the high is likely to simply reflect people moving in response to a record 57 price increases as wholesale costs rose.

About 11m households on default tariffs have seen their bills capped since 1 January, narrowing the gap between the best and worst deals to £150-£200, compared with more than £250 previously, according to switching site MoneySuperMarket.

The smaller savings had led the energy regulator to admit that switches may reduce by as much as 40%, which would wipe out the growth in recent years.

Lawrence Slade, chief executive of Energy UK, said: “My hope remains that, with the recent introduction of the price cap, we don’t see this element of competition undermined and switching levels fall, as is predicted in Ofgem’s impact assessment.”

Across the year, a net 1.7 million customers moved to small and mid-sized suppliers, rather than the big six that hold four-fifths of the market.

Small suppliers dominate the top of a new league table of customer satisfaction, with Which? reporting Octopus Energy the best in the market.

Bucking the trend was another small firm, Solarplicity – it came bottom of the consumer group’s ranking which surveyed 8,000 people on suppliers’ value for money, customer service and billing accuracy.

The big six occupied the bottom third of the table, with Scottish Power the worst of the six and SSE the best.

Rachel Reeves, Labour MP and chair of the cross-party business, energy and industrial strategy committee, said: “The Which? survey highlights once again that the big six are miserably failing their customers. Having ripped off loyal customers on SVTs (standard variable tariffs) for far too long, this survey shows that they aren’t delivering a service which is up to scratch either.

“Customers should continue to shop around because they cannot rely on energy suppliers giving consumers a good deal or delivering the quality customer service which they deserve.”


More people walking away from ‘Big Six’ energy firms

Consumers are increasingly switching to small and medium sized energy providers and shunning the “Big Six”, according to new figures.

One in five customers switched their energy provider in 2018 – an increase of 6% on the previous year.

Data from industry association Energy UK found that 5.8 million changed their supplier last year, or an average of just under half a million each month.

It continues a trend of year-on-year increases in energy switching, Energy UK said, with around 30% – or 1.7 million customers – moving to a small or mid-tier supplier.

Recent research by consumer watchdog Which? found that five small energy suppliers topped the rankings for customer satisfaction.

Octopus Energy came top with a satisfaction score of 80%, closely followed by Robin Hood Energy and So Energy in joint second place with 78% and Ebico and Tonik Energy in joint fourth position on 76%.

But bucking the trend was small supplier Solarplicity – it was the worst energy firm according to its customers, with an overall score of just 44%.

Which? also noted that three small firms – Spark Energy, Extra Energy and Economy Energy – have ceased trading since the survey was carried out, although Spark still operates as a brand name after being taken over by Ovo.

Their results aren’t included but all performed poorly, Which? said.

The Big Six – British Gas, EDF Energy, Eon, Npower, Scottish Power and SSE – were relegated to the bottom third of the rankings.

None received an overall customer score higher than 58%.

Alex Neill, Which? managing director of Home Products and Services, said: “Our survey shows the importance of value for money and good customer service – energy suppliers delivering both to their customers tend to be thriving, while the Big Six and other poorly-ranked firms are paying the price for not giving customers what they want.”

Rachel Reeves MP, chair of the Business, Energy and Industrial Strategy Committee, said: “The Which? survey highlights once again that the Big Six are miserably failing their customers.

She added: “Customers should continue to shop around because they cannot rely on energy suppliers giving consumers a good deal or delivering the quality customer service which they deserve.”

The figures come at the start of “Big Energy Saving Week” – an initiative run by Citizens Advice and the Department for Business, Energy and Industrial Strategy.

A spokesman for Citizens Advice said despite the introduction of a price cap on energy bills last year, households could save more than £150 each year by switching supplier.

Gillian Guy, chief executive of Citizens Advice, said: “These figures show that there are still large numbers of people paying over the odds on their energy bills.

“While the price cap will mean people paying a fairer price, there are still substantial savings to be made.”


Brexit: Losing energy links to Europe after no-deal will cost UK more than £2bn every year, experts warn

no-deal Brexit could cost the UK £2.2bn every year as the network connecting the nation’s electricity supply with its European neighbours would no longer function effectively.

Environmental think tank Green Alliance issued the warning as Britain’s future clean power supply looked uncertain following a string of failed nuclear power projects.

With Japanese firm Hitachi pulling out of the planned Wylfa plant in Wales, the UK now faces a “nuclear gap” of about 15 per cent in its future electricity supply.

Environmental groups say the gap can be plugged with renewable energy, and business secretary Greg Clark acknowledged the tumbling price of wind powerwas making it a more desirable option than nuclear.

However, concerns still remain around how variable power supplies, such as wind and solar, can provide the grid with reliable power.

One way around this problem would be to invest in networks that span multiple countries, meaning when the wind is not blowing in Britain energy can be provided from somewhere else.

Such a network would also provide a market for the country’s renewable electricity at times of surplus. In 2017, energy trading across borders brought £700m into UK markets.

Despite these benefits, and projects in the pipeline to link the UK up with Belgium and Norway, Britain remains one of the least connected countries in Europe.


Report: Renewables to overtake fossil fuels in UK energy mix in 2020

Renewables are on course to overtake fossil fuels for the first time as the UK’s primary electricity source as early as 2020, according to the latest market forecast from EnAppSys.

If current trends continue, the market analyst predicts growing renewable power sources such as wind and solar will generate 121.3TWh or electricity over the calendar year of 2020, pushing ahead of declining coal and gas-fired power sources with a forecasted 105.6TWh of generation.

It would mean that, for the first time, more of the UK’s electricity would be provided by renewables than any other aggregated power source, including fossil fuels, nuclear, and interconnectors, according to yesterday’s report.

The forecast assumes current trends of declining fossil fuel generation and rising renewables generation continue at the same annual rate. In 2018, coal and gas fired power stations produced a combined 130.9TWh, a 6.7 per cent fall from the previous year’s 140.3TWh, the report states. Meanwhile, renewable sources delivered 95.9TWh last year, rising 15.2 per cent from 2017 – a strong performance bolstered by the UK’s increasing offshore wind capacity.

Overall, renewables accounted for a third of all power generation in the UK, with wind providing 17 per cent, solar four per cent, and biomass 11 per cent, analysis by Carbon Brief found earlier this month. Nuclear also accounted for a fifth of UK generation, taking low carbon power’s share of the mix to a record high of 53 per cent. Gas and coal, meanwhile, provided 39 per cent and five per cent respectively.

Paul Verrill, director of EnAppSys, said the rise of renewables, particularly offshore wind, was driving major changes in the UK energy market, with conventional power generators having to adapt to lower levels of activity and find ways of offsetting any lost income as a result.

He said he expected wind and the wider renewables sector to continue squeezing levels of output from fossil fuel generators in the coming years. “With the moratorium on onshore wind and reductions in capital cost of offshore wind farms, it is likely that more of these offshore projects will come on stream in future years, which will drive even higher levels of renewable output,” he said. “New electrical transmissions infrastructure that came on line in 2018 will increase further the contribution of renewable energy to the UK fuel mix but constraints still persist despite the investments.”

Verrill also pointed to further ongoing challenges for fossil fuel generation in light of the suspension of the Capacity Market mechanism late last year, which was aimed at ensuring back up baseload power from conventional generators on days of low renewables generation and high demand.

“Against this backdrop, the margins for thermal power generation fell to 2014 price levels as the impact of reduced demand, increased levels of wind generation and very competitive market dynamics placed downward pressure on profits,” he explained. “This dynamic should settle down over time, but with rising competition in the market driven by the growth of renewables it will become necessary to reinstate the Capacity Mechanism payments or some other alternative to fill the gap created by the lost income. If this is not the case, it’s likely that plant closures will be necessary to remove oversupply from the system and this will lead to decreased security of supply.”