BRITISH Gas is working up radical plans to axe rip-off standard gas and electricity tariffs in a last ditch bid to avoid a price cap.
Britain’s biggest energy supplier instead wants to shift nearly five million loyal customers onto insurance-style annual deals – which would encourage households to look for a cheaper rate every 12 months.
The shift would be a huge victory for the Sun’s ‘Power to the People’ campaign – and force rivals to follow suit.
It came as Energy Secretary Greg Clark yesterday once more warned that the Government could legislate to introduce a price cap if companies carry on “abusing” customers.
Speaking at a Sun fringe meeting at the Tory Conference yesterday, British Gas exec Sarwjit Sambhi said the company wanted an industry wide ban on SVTs – default tariffs which are typically £300 more expensive than online rates.
But he said the company was already trialling replacement tariffs.
And he revealed: “We would not rule out that at some point we may decide to go unilaterally.”
Insiders said confirmation could come immediately after Ofgem sets out its own plans to tackle an estimated £1.4 billion rip-off in the industry.
Ministers have demanded an end to SVTs, because they are typically held by customers who haven’t switched suppliers for years.
Speaking yesterday, Greg Clark dismissed claims the Government had dumped its Election Manifesto pledge to cap prices. He said Ofgem had the necessary powers to act.
“Suppliers know the detailed behaviour of customers and choose those who are unlikely to switch because they trust the brand or have been with them for decades.
“We know that in the modern age it’s possible for suppliers to have that information and they abuse that trust by racking up the bills.”
Gas storage firm InfraStrata said a proposed Northern Ireland project’s potential “exceeds expectations”.
The AIM listed firm wants to develop an above ground gas storage plant at Islandmagee in County Antrim.
Nearly £500,000 has been conditionally raised through a placing to meet costs associated with the project for the next six months.
In an update, InfraStrata said that since June “considerable efforts” have been made exploring a range of both short and long-term options for future value creation for the company and the project.
And the shelving of Centrica’s Rough storage gas field – which has suffered significant difficulties in recent years – had increased the need for such sites.
The firm said in a statement: “The project has shown that it exceeds the board’s expectations in terms of its ultimate potential.
“In the board’s opinion, this highlights the relative undervaluation of the company at this time.
“The board believes that the recent announcement of the phased closure of the Rough gas storage facility by Centrica plc improves the significant potential of the project as a result of this substantial reduction in gas storage capacity in the UK.”
InfraStrata is in talks with a “number of” parties intere4sted in progressing the Islandmagee project.
The company has not ruled out a possible sale of the project and is also looking for longer term funding, including from the European Union.
Adrian Pocock, Chief Executive of InfraStrata, said: “The company stands at a significant crossroads and I am pleased to confirm that we are extremely encouraged by developments since being elected onto the board.
“The project shows excellent scope to create value for our shareholders. The positive engagement that we have achieved with stakeholders and potential and existing partners has been remarkable.
Energy security of both gas and electricity supplies in the whole of the UK is likely to be adversely affected once Centrica’s Rough facility closes in around two years, and there are increasing concerns and focus on energy security.
“We are pleased that we have the opportunity to support the UK and Irish Governments and their respective economies in ensuring continuity of supply.
“We anticipate that once the UK leaves the EU, it will no longer be able to depend upon the EU requirement for member states to support each other at times of peak energy demand.
“The revised strategy of pursuing new potential monetisation routes in conjunction with a flexible, dynamic modus operandi ensures that opportunities are maximised to the enhancement of the Company’s financial position and future.”
The owner of the UK’s largest power station has argued its giant plant in North Yorkshire can still play a meaningful role in the country’s energy system, even as more electricity is provided by renewables and smaller plants that fill gaps when wind and solar power is not available. Drax expects its plant, which covers a 2,500 acre site, will play a significant role providing services to the UK’s National Grid, such as helping to keep the electricity fed through the system at a stable frequency and providing reserve power to cater for unplanned losses of generation or peaks of demand. The company is examining its options for the plant as the UK aims to phase out coal fired power stations entirely by 2025. Three of the six coal-fired units at the site already burn wood biomass pellets and trials have been carried out to convert a fourth. Drax is also applying for planning permission to convert the remaining two units to gas and build a battery storage facility for electricity that could be one of the biggest of its kind in the world. Andy Koss, chief executive of Drax Power, said the plant’s future lay in the provision of flexible services, despite a decision by some energy companies to move away from large central power stations. “The key is around flexibility in the system and we want to be a provider of that flexibility,” Mr Koss said on Wednesday. Drax forecasts that providing services to National Grid, which operates the UK’s high voltage electricity transmission system, will be a growth area, as changes to Britain’s energy mix provide new challenges in balancing supply and demand. Centrica, the owner of British Gas, earlier this year sold its last big central power stations in the UK, betting that smaller plants that can be fired up quickly will be more relevant in future to smooth gaps in supply when renewables are not generating electricity. Drax’s plans for the North Yorkshire site would create the biggest gas plant in the UK, with a proposed generation capacity of up to 3.6 gigawatts. The economics of large gas plants have, however, been questioned in recent years and developers have been unwilling to go ahead without government subsidies. The latest government subsidy auction, held this month, also revealed a sharp fall in the costs of developing offshore wind farms. However, Mr Koss insisted that new combined cycle gas turbine plants would be needed in future as the UK’s remaining coal stations close by 2025 and ageing nuclear plants are decommissioned by 2030. Gas plants were also good for providing the sort of flexible services National Grid requires, he added.
Temporary shutdown of the four generation units of the Tricastin nuclear power plant
EDF takes note of the decision taken by the French Nuclear Safety Authority (ASN) on 28 September 2017 requesting that EDF temporarily shut down the four generation units of the Tricastin nuclear power plant (Drôme, France), while strengthening work is carried out on a small section of the dyke located to the north of the power plant bordering the Donzère-Mondragon canal.
As an operator that takes responsibility for the safety of its installations, EDF does not share the view that the four reactors need to be shut down for the duration of the work. EDF will nevertheless implement the ASN decision without undue delay.
The geotechnical surveys carried out on this dyke in 2015 and 2016, supplementing those performed in 2013 and 2014, revealed that a small section of the dyke required reinforcement. EDF has however demonstrated to the ASN that the dyke is capable of withstanding an earthquake known as a “Maximum Historically Probable Earthquake” (MHPE). This is an earthquake that is more severe than the historical earthquakes observed in the vicinity of the power plant, located in the most damaging position for the installations.
On the basis of the analyses and calculations performed it was not possible to unequivocally demonstrate the robustness of the dyke in the event of an earthquake known as a “Safe Shutdown Earthquake”, a hypothetical earthquake releasing energy five times greater than that of an MHPE. On 18 August 2017, EDF therefore declared a “significant safety event” at level 1 on the INES scale (the 8-level International Nuclear Events Scale).
EDF submitted a two-phase reactive action plan to the ASN:
Within one month, dyke strengthening work will be carried out in order to guarantee its resistance in a Safe Shutdown Earthquake situation
Ahead of this strengthening work, additional protection is currently being installed on the existing peripheral protective wall and will be operational within a few days. This measure ensures that no water would reach the reactors in the event of a Safe Shutdown Earthquake during the work period.
Given these arrangements, EDF is convinced that the safety of the installations is guaranteed and considers the reactors’ shutdown unjustified.
The shutdown of the reactors required by the ASN has led the Group to revise its nuclear generation target for the year 2017 to 385-392 TWh, depending on the actual duration of reactors’ shutdown, compared with a previous target of 390-400 TWh.
The EDF Group confirms its 2017 and 2018 financial targets in the current price environment.
A key player in energy transition, the EDF Group is an integrated electricity company, active in all areas of the business: generation, transmission, distribution, energy supply and trading, energy services. A global leader in low-carbon energies, the Group has developed a diversified generation mix based on nuclear power, hydropower, new renewable energies and thermal energy. The Group is involved in supplying energy and services to approximately 37.1 million customers, of which 26.2 million in France. The Group generated consolidated sales of €71 billion in 2016. EDF is listed on the Paris Stock Exchange.
Energy bills across the UK are rising at their fastest rate in more than three years, dealing a sharp blow to savers as wages remain stagnant, new data reveals.
Figures published on Thursday by consumer website MoneySavingExpert.com show that average energy costs have increased by 5.3 per cent over the last year, which marks their steepest rise since February 2014. The cost of electricity alone, the data shows, has risen by 9 per cent.
The website publishes a monthly bills tracker, which examines the cost of living. Unlike official inflation figures, it strips out items that the average UK household is unlikely to buy on a monthly basis, like rugs, door handles and knitting wool.
British Gas price hikes make Friday 2017’s most expensive day
The latest survey to the end of August shows that overall household costs increased by 2.4 per cent over the last year. Rent rose by 0.9 per cent, water by 1.8 per cent, insurance by 8 per cent and internet and phone connections by 2.3 per cent.
Price comparison website MoneySuperMarkethas estimated that that change will collectively cost households £235m per year.
Earlier in September, Energy UK, the trade association for the UK energy industry, said that nearly half a million customers switched their supplier in August 2017.
But MoneySuperMarket estimated that around 70 per cent of UK households are still on expensive SVTs from the Big Six providers – British Gas, EDF Energy, nPower, E.On, Scottish Power and SSE.
Business and Energy Secretary Greg Clark wrote to regulator Ofgem in June asking what action it intended to take to safeguard customers on the poorest value tariffs and the future of the standard variable tariff.
Since then, Ofgem has committed to taking action, saying that it would consult with consumer experts to develop ways of safeguarding tariffs.
The UK government today awarded contracts worth £176m to 11 low-carbon electricity schemes, with offshore wind the big winner. These projects will generate nearly 3% of UK electricity demand.
Two offshore wind schemes won contracts at record-lows of £57.50 per megawatt hour (MWh). This puts them among the cheapest new sources of electricity generation in the UK, joining onshore wind and solar, with all three cheaper than new gas, according to government projections.
The offshore wind schemes are also close to being subsidy-free: the Department for Business, Energy and Industrial Strategy (BEIS) expects wholesale power prices to average £53/MWh in the period from 2023 to 2035, covering the bulk of their 15-year contract period.
The auction results shift the conversation, from renewables being expensive, towards how cheap, variable zero-carbon power can be integrated into the grid, while maintaining sufficient supplies of power throughout the year.
Offshore wind results
Today’s auction is the second competitive auction and third award of contracts for difference (CfDs). These are contracts at a fixed “strike price” and most of them last for 15 years. During the contract period, projects are paid the difference between a reference wholesale price and their strike price. If wholesale prices rise above the strike price, the project pays back the difference.
This guaranteed income allows developers to get more favourable terms from investors. This cuts the cost of borrowing, which makes up a large part of the total price tag for low-carbon generation.
In the first round, in 2014, the government awarded15-year CfDs to five offshore windfarms at £140-150/MWh. These projects are coming online during 2017 and 2018. These awards were criticised by the National Audit Office, which said competitive auctions could have cut costs.
In the first CfD auction, held in 2015, contracts worth £315m were awarded to 27 schemes, with a total capacity of 2.1 gigawatts (GW). The majority of this was offshore wind, at prices of £120/MWh for projects coming online in 2017/18 and £114/MWh for 2018/19. Onshore wind and solar schemes supported in this first auction came in at around £80/MWh.
Today’s second CfD auction awarded £176m to 11 schemes totalling 3.3GW, of which three offshore wind projects made up 3.2GW. The 860 megawatt (MW) Triton Knoll windfarm off Lincolnshire is due to come online in 2021/22 at a cost of £74.75/MWh.
The following year, the 950MW Moray Offshore Windfarm (East) and 1,360MW Hornsea 2 scheme will come online at a cost of £57.50. The total 3.2GW will cost an average of £64/MWh.
These offshore wind schemes will be phased, meaning only parts of their capacities will start generating power during the first year. This is expected to allow developers to take advantage of falling technology costs and the hoped-for availability of larger, more cost-effective turbines.
A number of small incinerators and biomass combined-heat-and-power plants were also awarded CfDs today at prices of between £40 and £75/MWh. Their total capacity is 150MW, the maximum allowed under auction rules set by BEIS.
The lower-than-expected prices in today’s auction mean BEIS was able to support 3.3GW of capacity despite only allocating £176m out of the £295m total it had available.
The government had previously promised to run three rounds of auctions, including today’s, with up to £760m available. It has yet to confirm if additional auctions will take place.
Cheaper than gas
This illustrates the most striking thing about the CfD auction results so far: wind and solar have consistently delivered far lower prices than expected. Indeed, BEIS had set a price target for offshore wind of £85/MWh in 2026, far higher than the contracts awarded today.
In late 2016, BEIS projections suggested offshore wind projects coming online in 2025 would cost around £100/MWh – far more than new gas and comparable with new nuclear. At the time, BEIS said onshore wind and large solar farms would be the cheapest new power sources.
(Note that BEIS has so far refused to run so-called pot 1 CfD auctions for onshore wind, solar and other “established” technologies. However, the 2017 Conservative manifestoleft the door open to offering support for onshore wind outside England.)
Levelised costs of electricity generating capacity coming online in 2025. PWR FOAK is first-of-a-kind pressurised water nuclear reactors. CCS is carbon capture and storage. CCGT is combined cycle gas turbine. OCGT is open cycle gas turbine (for peaking). R3 is the third round of offshore wind licences awarded by the Crown Estate. Source: BEIS projections.
Today’s auction has destroyed the 2016 BEIS projections, with offshore wind projects again coming in far cheaper than expected.
The chart below shows awarded CfD prices for wind and solar (blue and yellow lines) compared to the Hinkley C new nuclear plant (purple line), which has a 35-year CfD for £92.50/MWh. Also shown are current and expected wholesale power prices (black) and the projected cost of building large new gas-fired combined cycle plants (CCGTs, red).
Costs of UK electricity generation, £/MWh. Wholesale prices are actual (solid black line) and projected, (dashed line). Technology costs reflect awarded contracts and projections, see notes below for more details. Sources: BEIS projections, CfD auction results and Baringa Partners. Chart by Carbon Brief using Highcharts.
The chart shows that offshore wind, along with onshore wind and large solar farms, are all thought to be cheaper than new gas generation (see notes below for more on this comparison, which includes a rising carbon price reaching £49 per tonne by 2030).
By the mid-2020s, renewables will be cheaper than new gas even after accounting for the costs of integrating them into the electricity grid and providing backup to guarantee supplies.
Writing before today’s auction results, Gareth Miller, chief executive of consultants Cornwall Energy, wrote: “The traditional challenge [that] critics of onshore renewables have posed about whole system costs eradicating the competitive benefits of deployment start to disintegrate at these sorts of strike price levels.”
The best available estimates suggest these so-called whole-system costs will add around £10-15/MWh. This includes balancing unexpected short-term fluctuations in output and providing back-up capacity for cold, dark and still days in winter when renewable generation is low.
(Note that windfarms in the UK generate power almost all of the time, whereas their output varies. For example, offshore wind generated close to 100% of hours during November 2016. BEIS expects new offshore windfarms to have a load factor of close to 50%.)
System costs are expected rise to between £15 and £45/MWh if wind and solar supply half the UK’s power, up from 15% in 2016. The top end of this range reflects a very inflexible electricity grid. Costs would be at the lower end, if the government’s plans to encourage a flexible grid bear fruit.
The chart above shows renewables are also close to becoming subsidy-free, with prices approaching expected future wholesale costs. (Note this is before accounting for integration costs). For example, today’s £57.50/MWh offshore wind contracts are less than £5/MWh above the £53/MWh average wholesale price projected by BEIS for 2023-2035.
However, these contracts fall short of results in Germany, where Dong Energy has won the right to build offshore wind projects without subsidy. This subsidy-free price excludes some of the costs of connecting to the grid, which are included in the UK contracts.
As well as grid connection costs, contracts in Germany and the Netherlands can exclude site scoping and design, with developers competing to build already agreed projects. See this June 2017 Offshore Wind Journal article for more on how the UK system compares.
Today’s auction is likely to challenge preconceptions about renewable power. For example, Prof Dieter Helm, who is leading a government review on costs of energy, has said offshore windfarms will “never” be economic.
It might also increase pressure on the government to run auctions for onshore wind and solar, which are likely to be even cheaper. Consultants Baringa Partners say auctions could secure 1GW of onshore wind for £46/MWh, which would be effectively subsidy-free. Meanwhile, Cornwall Energy says some onshore schemes could offer CfD bids as low as £40/MWh.
Securing subsidy-free renewables would help fill the gap in electricity supplies, which is expected to open up in the 2020s as the UK’s remaining coal plants close, old nuclear retires and more stringent carbon targets start to bite.
(This gap will be even wider if electric vehicles raise demand, though this is unlikely to be significant during the next decade. It could be shrunk if the UK implements cost-effective energy efficiency policies that could cut household demand by a quarter).
On the other hand, despite rapidly falling prices, the UK must face the challenge of managing the variable output of wind and solar and integrating them into the electricity grid. Here, the government’s plans to encourage a more flexible grid will be key to keeping costs to a minimum.
Today’s results do not necessarily mean the UK can focus on renewables alone. The Committee on Climate Change (CCC) argues for a portfolio of technologies in order to keep options open for meeting long-term carbon targets. All of its pathways for the fifth carbon budget include renewables and at least one of either new nuclear power or carbon capture and storage.
Notes on the chart
The chart of electricity generation costs amalgamates several different sources of information. As noted below, these are not all strictly comparable. Nevertheless, the chart is indicative of the trends at play in the UK power market.
The wholesale power price is from the ICIS power index for past and current prices, with the 2017 figure a year-to-date average. Future power prices are central BEIS projections, published in 2017, amended for 2022 through 2025 with numbers published as part of today’s auction. Note that the latter are references prices, which are not strictly the same as wholesale prices.
The technology costs are shown in 2012 prices and include BEIS projections, awarded contracts and other estimates.
For nuclear, the strike price for Hinkley C is shown. Note that this is a 35-year contract, which spreads the cost over more years and hence depresses the price compared to the 15-year contracts for renewables.
On the other hand, strike prices tend to be inflated relative to the levelised cost of electricity (LCOE), shown for some of the technologies, which spreads the cost over the lifetime of each project.
(Update 12/9/17: The offshore wind strike prices of £74.75 and £57.50/MWh are equivalent to LCOEs of £65 and £51/MWh respectively, according to the Offshore Renewable Energy Catapult, a government-backed research and innovation centre.)
For offshore wind, the prices shown reflect already awarded contracts for each delivery year, with a straight line drawn in between years. For onshore wind, contract prices are shown for 2017, BEIS LCOE projections for 2018 and 2020, then an estimate from consultants Baringa Partners for 2022.
The solar line includes contracts awarded in the first CfD auction and then BEIS projections, which are likely to be an overestimate of the true costs.
For gas, the line shows BEIS projections. Note that this includes a rising price for wholesale gas and, more importantly, a rising carbon price that reaches £49 per tonne in 2030. It could be argued that this overstates the cost of gas generation. However, this rising price remains below one that would be consistent with meeting the UK’s legally-binding carbon budgets. An argument against including any carbon price amounts to an argument against meeting UK climate goals.
The LCOE and strike prices are good for comparing the costs of generating an additional megawatt hour of electricity. However, they are relatively poor metrics for comparing the cost and value of meeting all the needs of the electricity system.
UK households have forked out an extra £7.3 billion over the last five years by remaining customers of the Big Six energy firms, a new report shows.
Ofgem data compiled by energy provider Bulb found that families who held accounts with the biggest firms – including British Gas, SSE, E.ON, Npower, EDF and Scottish Power – for at least five years paid out an average £853 more than they needed to over the period
The report explained that while Big Six firms tend to offer cheaper fixed tariffs in order to “entice” new customers, those tariffs tend to expire within one to two years.
At that point customers are usually transferred to standard variable tariffs, which cost up to 30% more than their original plan.
The report went on to calculate the so-called “loyalty fee”, which measures the annual price difference between the average standard variable tariff at a Big Six firm compared to their cheapest tariff.
It found that the average loyalty fee for a UK household was £852.75 over five years – with an astonishing 8.5million British homes staying with one of the Big Six firms and not switching.
Bulb co-founder Hayden Wood said: “Loyalty towards a brand is often rewarded, yet households who’ve put their trust for years in a single energy company are being forced to subsidise others who switch every 12 months.”
He added: “These latest numbers show that so-called standard tariffs no longer have the customers’ best interests at heart. The Big Six need to show that they’re putting customers first, instead of profits.”
A recent poll by uSwitch found a third of Brits are already concerned about paying their energy bills this winter and more than half are struggling with their household finances.
British Gas became the latest Big Six energy supplier to hike prices at the start of August, when it confirmed that it was ramping up the cost of electricity by 12.5% for 3.1 million customers, despite falling wholesale prices.
The company had promised in December that it would freeze tariffs until summer 2017, while rivals including Scottish Power, E.ON and EDF raised their own bills near the start of the year.
Competitor SSE raised dual fuel prices by 6.9% in April, while Npower came under fire in February amid plans to hike gas and electricity prices by 9.8% – a move that added £109 to annual dual fuel bills.
Solar panel capacity is set to overtake nuclear worldwide for the first time within the next few months, according to expert predictions.
The total capacity of nuclear power is currently about 391.5 gigawatts but the total capacity of photovoltaic cells is expected to hit 390 gigawatts by the end of this year with demand growing at up to eight per cent per year, according to GTM Research.
While this would be a landmark moment for renewable energy, nuclear still generates much more electricity than solar – nearly 2.5 million gigawatt-hours a year compared to the latter’s 375,000 gigawatt-hours
Stephen Lacey, writing on GTM’s website, said: “It’s still going to be a record-breaking year for new solar capacity additions – yet again.
“The 81 gigawatts expected this year are more than double the amount of solar capacity installed in 2014. And it’s 32 times more solar deployed a decade ago. (In the year 2000, global installations totaled 150 megawatts.)
“One of the most telling statistics: By 2022, global capacity will likely reach 871 gigawatts. That’s about 43 gigawatts more than expected cumulative wind installs by that date. And it’s more than double today’s nuclear capacity.”
While solar accounts for about 1.8 per cent of global electricity generation today, the International Energy Agency has predicted this could rise to 16 per cent by 2050 under a “high-growth scenario”, which would make it the largest source of energy in the world.
And Mr Lacy said: “In the last three years, growth rates and cost reductions for solar have far exceeded projections. Meanwhile, high costs, slow construction and competitive renewable alternatives are causing the global nuclear industry to falter.
“The trend lines are becoming clearer every year.”
The Sun delivers enough energy to the Earth in an hour to provide humans with everything they need for an entire year
There have been more than 36,000 switches in the first three months since the launch of the newly competitive water retail market according to data published today by the market operator, MOSL.
Figures also released today by the Consumer Council for Water reveal that during the same period, there were 370 complaints from non-household customers (compared to 232 in the same quarter last year), with billing-related issues remaining the most common cause of complaint.
Commenting on today’s figures, Ofwat Chief Executive Cathryn Ross said:
“This first set of data is important because it gives us a baseline to monitor against and helps us to identify and address emerging issues.
“It is early days, but we are seeing some encouraging signs with new retailers, new deals, and, crucially, customers saving money and water.
“There have been more than 36,000 switches and around 60 per cent of those have come from low water users – more likely to be SMEs. That is significant, because we want to make sure this market works for all customers, not just the very large companies with specialist procurement divisions.
“In addition to those who have switched, we have heard that many others have agreed new deals with their current retailer.
“More needs to be done however; comparing offers is still not as easy as it needs to be and we have told retailers they must remedy this.
“We will continue to monitor the market closely to make sure it works for all and continue to meet and listen to customers, whose views will shape our work.”