PowerLight’s technology uses lasers to charge things over “free space” or fiber optic cables.
BP, the oil and gas major, has significantly increased its global outlook for wind and solar energy.
The main scenario in the company’s latest annual “Energy Outlook”, released yesterday, shows renewables rising four-fold to 2,000 million tonnes of oil equivalent (Mtoe) by 2035. This is an upwards revision of around 400Mtoe compared to last year’s main forecast.
The projections also show, for the first time, global oil demand peaking by 2040. Oil remains the world’s largest fuel source, however.
This 2018 edition of BP’s outlook also projects coal will peak before 2030, an even earlier projection than it gave last year.
BP’s report focuses on its new “evolving transition” scenario, which replaces its “base case” scenario from previous years (see more on this below). However, it no longer says this is the “most likely” future scenario.
In this new projection, rising energy demand over the next 20 years is driven by fast-growing developing economies, with China and India accounting for half of the growth.
As the graph below shows, it projects a peak for both coal and oil in the coming decades, but continually rising demand for gas.
The path of global energy demand to 2040 by fuel, according to BP’s “evolving transition” scenario, in millions of tonnes of oil equivalent (Mtoe). Wind & solar includes other non-hydro renewables, but excludes biofuels. Source: BP Energy Outlook 2018. Chart by Carbon Brief using Highcharts
Oil consumption peaks for the first time at some point between 2035 and 2040. However, even in 2040, it will sit at around 4,800Mtoe, more than 50% higher than in 1990.
This is driven in part by falling demand from transport due to vehicle efficiency improvements and alternative fuels, says BP. By 2040, 40% of new cars sold are electric vehicles (EVs) in the evolving transition scenario, while 31% of kilometres travelled by car are in EVs. The scenario expects energy use in transport to plateau around 2035-40.
In 2018 BP Evolving Transition scenario, oil demand for cars remains same in 2040 as 2016 despite doubling of kms travelled globally #BPstats
— Jim Watson (@watsonjim2) February 20, 2018
Oil use in transport stops growing towards 2030. Non-combusted uses of oil – such as feedstocks for petrochemicals – become the main source of growth demand after 2030. However, oil demand still accounts for around 85% of total transport fuel demand in 2040.
Some have noted that BP’s Outlook has less to say on forms of transport other than cars, with little on aviation, shipping and trucks despite these sectors accounting for the biggest slice of oil demand growth for the industry.
The projection also shows a rising gas demand steadily closing in on oil. In 2040, 26% of primary energy comes from gas in the scenario, compared to 27% from oil.
Meanwhile, as the graph shows, the scenario showscoal peaking between 2025 and 2030, hovering at around 3,800 Mtoe by 2040.
This decline is driven by falling coal use in China, where the BP report says it seems increasingly likely coal consumption has peaked already.
The outlook shows China’s carbon emissions from energy use peaking in the mid-2020s. Renewables, nuclear and hydro account for more than 80% of the increase in China’s energy demand by 2040, with renewables overtaking oil to become the country’s second largest energy source.
However, the scenario show coal remaining the dominant energy source for power in the rest of Asia, accounting for 45% of India’s sizeable increase energy demand.
Renewable energy is the fastest-growing energy source in the main scenario, accounting for 40% of the energy increase in 2040.
Demand for wind and solar reaches around 2,000Mtoe in 2035, quadrupling from the 500Mtoe used in 2015. A further 500Mtoe is added by 2040. By this time wind and solar will meet around 14% of the world’s primary energy consumption.
Carbon Brief’s chart below shows how BP’s projections for 2035 compare since 2011.
The revision is particularly striking this year for wind and solar. As the chart shows, the projection for 2035 has risen significantly compared to the base case scenario last year. BP now expects around 400Mtoe higher demand of wind and solar by 2035 than the 1,600Mtoe forecast in the 2017 report.
How the BP Energy Outlook has changed since it was first published in 2011. Red lines show the 2018 “evolving transition” view for each fuel, in millions of tonnes of oil equivalent (Mtoe). Blue lines show previous years’ “base case” forecasts. Wind & solar includes other non-hydro renewables, but excludes biofuels. Source: BP Energy Outlook 2018, previous Outlooks and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
Meanwhile, the charts show that BP has lowered its outlook for hydro and nuclear.
As the charts above show, the new projection shows coal peaking before 2030, earlier than in the “base case” scenario last year which foresaw the peak occurring before 2035. This year’s outlook shows coal accounting for 21% of primary energy demand by 2040, down from 28% in 2016.
China accounts for almost 90% of the total growth in nuclear up to 2040, BP’s report says, with its share in China’s energy demand increasing from 2% today to 8% by 2040. Butdeclines are seen in both the EU and US as aging nuclear plants are retired and not replaced.
It is worth a cursory note to emphasise that none of the scenarios in the energy outlook are predictions. Instead, they are modelled scenarios based on a range of different inputs. As BP puts it:
“These scenarios are not predictions of what is likely to happen or what BP would like to happen. Rather, they explore the possible implications of different judgements and assumptions by considering a series of “what if” experiments.”
As Carbon Brief’s comparisons of earlier outlooks shows, BP has repeatedly underestimated the rise of renewables, as well as overestimating the demand for coal.
For example, as the chart below shows, the 2014 Energy Outlook put wind and solar demand at around 1,100Mtoe in 2035; by the 2017 Energy Outlook this had been revised up to 1,600Mtoe in 2035.
This year’s outlook, the seventh report in a row to raise projections for wind and solar energy, puts it at around 2,000Mtoe.
The chart below shows how BP’s outlook for 2035 has shifted with each report since 2014, the first year which gave a forecast for 2035.
Top panel: How the BP Energy Outlook for 2035 has changed since 2014. Red bars show the 2018 “evolving transition” outlook demand for each fuel, in millions of tonnes of oil equivalent (Mtoe). Blue bars show previous years’ “base case” outlook. Lower panel: Year-on-year change in the 2035 outlook, percent. Wind & solar includes other non-hydro renewables, but excludes biofuels. Source: BP Energy Outlook 2018, previous Outlooks and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
Most significant are the steady steps down for the coal projections and upward steps for the wind and solar projections. Meanwhile, BP’s outlook for oil, nuclear and hydro has remained broadly consistent over the past five years.
It appears BP may have taken stock of this. In previous years, BP’s report focussed on its “base case”, which the firm said was the “most likely” future scenario, shown in blue in the chart above.
This year, BP has scrapped this “base case” and instead uses what it calls the “evolving transition” scenario as its reference scenario (red in the chart above). The new report stresses that this “does not imply that the probability of this scenario is higher than the others”.
The evolving transition scenario assumes that government policies, technology and social preferences continue to evolve “in a manner and speed seen over the recent past”. World GDP more than doubles by 2040, driven by increasing prosperity in fast-growing emerging economies.
This remains one of its highest emission scenarios, with carbon emissions increasing over 10% by 2040. BP notes that carbon emissions in this scenario are not consistent with achieving the Paris Agreement goals. This highlights “the need for a more decisive break from the past”, it says.
The CO2 emissions resulting from BP’s evolving transition scenario are shown in the graph below in orange. Note that projections go up to 2040 for the first time, rather than 2035 as in recent years.
Carbon dioxide (CO2) emissions projections to 2040 for six scenarios from BP. Source: BP Energy Outlook 2018, previous Outlooks and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
The chart also shows five alternative global scenarios referenced by BP in its 2018 outlook. The first two of these were also given in last year’s report.
- Faster transition (light blue), where global emissions fall 25% below 2016 levels by 2040, driven by lower oil, coal and gas demand, and more nuclear and renewables.
- Even faster transition (yellow), where global emissions fall 45% below 2016 levels by 2040, driven by even lower oil, coal and gas demand and a big rise in renewables. This recognises the far bigger change needed than the evolving transition scenario to meet climate goals. It is based on a sharp increase in the carbon price, policies to push energy efficiency and greater fuel switching, and higher use of Carbon Capture and Storage (CCS).
- Internal combustion engine ban (black), where electric car sales become 100% total car sales by 2040. Leading to almost 70% of vehicle travel to be powered by electricity.
- Less coal-to-gas switching (dark blue), where growth in natural gas is slower due to weaker policies promoting the switch from coal.
- Renewables push (red), where more support for renewables means they account for over 90% of power growth up to 2040, rather than 50% in the evolving transition scenario.
Note: In this article, Carbon Brief has rounded BP’s projections to the nearest 100Mtoe. See the graphs for more precise numbers.
The post Analysis: BP significantly upgrades its global outlook for wind and solar – again appeared first on Carbon Brief.
Ending the world’s fossil fuel subsidies would reduce global CO2 emissions by 0.5 to 2.2 gigatonnes (Gt) per year by 2030, a new study says.
The research, published by Nature Energy, concludes that the removal of subsidies would lead to bigger emissions reductions in oil and gas exporting regions, such as Russia, Latin America and the Middle East, than promised by their Paris Agreement pledges.
In all other regions, removing fossil fuel subsidies would not have as large an impact as the Paris pledges, the lead author tells Carbon Brief.
However, a researcher not linked to the report tells Carbon Brief that comparing the effects of subsidy removal to the Paris pledges is “unnecessary and inappropriate”, since these economy-wide pledges are generally composed of many other policies and actions than just subsidy removal.
Ending financial support for fossil fuels has long been cited as an important way to reduce the world’s greenhouse gas emissions. Both the G7 and the G20 have pledged to end “inefficient” fossil fuel subsidies – the G7 by 2025, and the G20 with no fixed end-date.
The new research analyses the implications for mitigation efforts in different regions of the world of removing all fossil fuel subsidies.
The researchers built a global dataset of subsidies under both high and low oil prices, and worked with five different modelling teams to look at the impact of removing these subsidies on emissions.
The study found the removal of subsidies would reduce the globe’s CO2 emissions by 0.5-2.2Gt per year compared to a business-as-usual scenario by 2030, equivalent to a 1-5% reduction.(Note though, that under a business-as-usual case overall emissions would increase substantially even with this reduction).
The graph below shows the impact of subsidy removal on emissions in each of the five models used in the study, compared to each model’s baseline, for low (left) and high (right) oil prices. The emissions reductions expected from the Paris pledges (formally known as Nationally Determined Contributions, or NDCs) are also shown, separated into “conditional” (total commitments dependent on international action) and “unconditional” NDCs.
As the graphs show, there is little difference in emissions reductions between low and high oil price scenarios by 2030, although more variation is seen by 2050.
The paper characterises 1-5% reduction by 2030 under both the high and low oil price scenarios as a “small decrease” of CO2 emissions. However, Peter Erickson, climate change policy researcher at the Stockholm Environment Institute (SEI) says such a reduction seems a substantial amount. He tells Carbon Brief:
“That is only ‘small’ compared to the gargantuan size of the problem, which necessarily involves many, many solutions.”
Another report estimating the climate impacts of removing fossil fuel subsidies, released last year by the Global Subsidies Initiative (GSI) and the Overseas Development Institute (ODI), found it would reduce the world’s emissions by 37Gt CO2 between 2017 and 2050.
This would average of 1.1Gt CO2 per year, thus falls towards the lower end of the range given in today’s paper of 0.5-2.2Gt CO2 reduction per year. However, it is worth noting the GSI paper only looked at production subsidies, whereas today’s paper includes both consumer and production subsidies.
The study compares the modelled emissions reductions due to removing fossil fuel subsidies in different countries to what they promised in their Paris pledges.
According to the study, current climate pledges add up to a decrease of 4-8Gt CO2 from fossil fuels and industry. Therefore, the 0.5-2.2 Gt CO2 reduction found in the study translates to 6-55% of the emissions reductions expected from these pledges.
Jessica Jewell, researcher at the International Institute for Applied Systems Analysis (IIASA) and lead author of the paper, says the study found the emission reductions would vary substantially by region. She tells Carbon Brief:
“So, in oil- and gas-exporting regions [such as Russia, Latin America and the Middle East and North Africa], removing fossil fuel subsidies would equal or exceed emission reductions pledged under the Paris Agreement. But, in all other regions, removing fossil fuel subsidies would underperform emission reductions already pledged under the Paris Agreement.”
However, Erickson argues it does not seem fair to compare the impact of subsidy removal to the Paris pledges. He tells Carbon Brief:
“The constant comparisons to NDCs is unnecessary and inappropriate. NDCs are generally economy-wide emissions pledges. Fossil fuel subsidy removal is but one type of policy to help countries achieve this, but also to yield other benefits.”
He adds that fossil fuel subsidy removal has CO2 benefits that extend beyond territorial boundaries, therefore may not be captured within an NDC.
The paper also finds that in some countries, such as India, emissions could increase if fossil fuel subsidies are removed.
This could occur if, for example, the removal of subsidised oil and gas resulted in the increased use of coal rather than an increase in energy efficiency or renewables.
Erickson says the finding in some models that coal-rich nations would increase their emissions in the absence of subsidies is “not surprising” and “a function of their applying a single global policy”. He says:
“It would be interesting to see them test this finding against alternate assumptions about declining cost of renewables, for example, as well as comment on the political economy dynamics that may make a switch to coal in some regions no longer as feasible due to changing political and social norms.”
The paper also finds removing fossil fuel subsidies would not strongly stimulate the growth of renewable energy by 2030, leading to an increase of around two percentage points. However, it is worth noting that the penetration of renewables is not in itself a specific policy goal of fossil fuel subsidy reform.
The paper also finds that subsidy removal would reduce the average global carbon price needed to achieve modest climate goals (2–2.3C by 2100) by 2-12% in 2020-2050, assuming low oil prices are maintained.
The paper warns that its findings show the impacts that subsidy removal might have on “poor people” need to be taken into account.
For instance, the authors express concern that the removal of subsidies in some areas could mean the switch away from burning firewood and charcoal becomes out of reach for “the poor”. Jewell tells Carbon Brief:
“Lower income regions are the regions that subsidies actually cost less when oil prices are lower. And those are the regions where it may be more difficult to remove subsidies from a social perspective, because those are the regions where it could affect more people living below the poverty line. So supportive policies really need to be put in place to remove subsidies there.”
Shelagh Whitley, head of the climate and energy programme at the Overseas Development Institute (ODI), a UK-based thinktank which publishes regular reports on fossil fuel subsidies, tells Carbon Brief it is “quite obvious” that you need to use some fossil fuel subsidy reform savings to protect the poor from their effects. She says:
“I think we know that that’s true, so subsidies benefit the rich more, but when they’re removed they will have a greater impact on the poor in terms of their spending capacity etc.
“That’s why you often see significant portions of the fiscal space that’s created through subsidy reform then being redirected to other social protection instruments that will particularly support the poorest and more vulnerable.”
In Indonesia, for example, she says, subsidy reform has led to extra support for free healthcare, youth social programmes and even cash transfers to the poorest.
The study also notes that today’s low oil prices provide a unique political opportunity to remove subsidies, having a large effect on emissions but affecting a comparatively small number of poor people. (Note, though, that oil prices have increased substantially in the past few years, reaching around $60/barrel over the past few months up from $30/barrel in early 2016).
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Onshore wind is key to securing lower industrial electricity prices for the UK, a new report says.
Unlocking investment in the renewables, which offer the cheapest sources of electricity, is one of the recommendations of today’s University College London (UCL) report, prepared for the Aldersgate Group, an alliance of business, academic institutions and NGOs.
The report also finds that continental industrial power prices are often lower than those in the UK because of better links between neighbouring electricity grids, “activist” industrial policy and reliance on old generating capacity that is nearing the end of its life.
It confirms that climate policy costs are not the decisive factor. Prof Michael Grubb, professor of energy and climate change at University College London and one of the report’s two authors, tells Carbon Brief: “It’s kind of nonsense, the idea that it’s driven by carbon-related policies.”
Today’s report is the most comprehensive attempt so far to examine UK industrial electricity prices in an international context. As it notes: “Much of the UK debate on electricity prices has been at a level of either technical detail, or sweeping (and often questionable) generalisations.”
The report comes in the wake of the government’s “Cost of Energy Review”, written by the University of Oxford’s Prof Dieter Helm. This was supposed to clear a path to the government’s manifesto pledge of having the “lowest energy costs in Europe, both for households and business”.
The manifesto, in turn, was co-authored by Nick Timothy. The former policy adviser to prime minister Theresa May had masterminded the Conservative election campaign, after which the party lost its majority. Since losing his job, Timothy has continued to attack climate change policy, arguing it is “impos[ing] higher energy costs and lower industrial output”.
In contrast, the government’s independent Committee on Climate Change (CCC) said that wholesale costs and network charges were to blame for higher industrial electricity prices, rather than climate policy. It said last year:
“Differences in low-carbon policies cannot explain the difference in electricity prices, which stem primarily from higher wholesale and network costs…It is not clear why these costs are higher in the UK than in many comparable countries.”
Today’s report confirms and expands on this. It then offers ways to minimise costs in future.
Industrial electricity prices
Since 2000, UK industrial electricity prices have more than doubled. Most of this was due to rising international fossil fuel prices before 2008, when the UK passed its Climate Change Act.
The UK is highly exposed to wholesale gas prices, the report notes, since the liberalised market of the 1990s led to the “dash for gas” and increased reliance on the fuel.
After 2008, prices continued to rise in the UK, but also in the EU, as the chart below shows.
After 2012, UK industrial electricity prices started to diverge from the EU average. A particularly large spike in euro-denominated UK power prices, around 2015, was due to the strength of the pound, whereas sterling-denominated prices held steady.
This exchange-rate effect harmed the competitiveness of UK industry by raising its cost base relative to overseas firms – and not just in terms of energy. It also made UK exports relatively more expensive. The pound has since fallen back to levels seen in 2010 or 2011.
Other factors driving the divergence with other EU countries include the UK’s exposure to gas, noted above, with prices peaking in 2013, well after a peak in coal prices. Like the UK, Italy is also reliant on and exposed to gas.
In contrast, France gets most of its electricity from nuclear plants built in the 1970s and 80s, while German electricity prices tend to be set by coal. You can see these differences in the map, below.
Shares of EU member states’ electricity consumption in 2017 met by coal (black shading, top left), gas (blue), nuclear (pink). Darker colours show heavier reliance on that source. Source: The European Power Sector in 2017, Sandbag and Agora Energiewende. Maps by Carbon Brief using Highcharts.
UK prices after 2012 were also driven by rising investment in the electricity sector, after a lack of investment during the 2000s, and the carbon price floor, the UK’s unilateral top-up carbon tax. Note that while this contributed to a growing gap between UK and EU average prices after 2012, it cannot explain this difference (see below) and some industrial firms are compensated for the cost.
It is this divergence in relative industrial electricity prices after 2012 that has caught the attention of UK commentators and policymakers. Indeed, the fact that UK prices are higher than in France or Germany is well-established, even if the reasons behind this have not been understood.
For the average industrial user in the UK, prices in 2016 were 35% above the level in 2008 and a similar amount above the EU average, which was relatively static over that period, the report says. This difference is illustrated in the chart on the left, below.
(The report’s focus is on four EU countries: the UK, France, Germany and Italy. These countries span nearly the full range of EU industrial electricity prices and all have large industrial sectors. The chart shows euro-denominated prices, so part of the fall from 2015 to 2016 in the UK is due to the falling pound.)
The chart on the right, above, shows that with maximum compensation, UK users in 2016 faced lower prices than in Germany or Italy, while they remained slightly above those in France.
(Note that other countries make greater use of exemptions, instead of compensation. This makes the UK look worse than it actually is, in the pre-compensation figures published by Eurostat, which can, therefore, be “quite misleading”, Grubb says. The UK is now moving towards exemptions.)
Grubb tells Carbon Brief: “It’s quite a messy picture, but for the big companies with full compensation, they’re pretty much at average EU prices. For those industries that don’t have [compensation], they are clearly in the high end of the EU.”
If prices for the largest industrial firms are around the EU average, this potentially undermines the whole premise of recent concern over “disadvantaged” UK industry. On the other hand, it’s fair to say that not all firms receive compensation.
Eligibility for compensation is complex and varies between different schemes and countries, but the broad outlines are determined by EU-wide state aid rules. In principle, firms that face competition from overseas and with high electricity costs as a share of their outgoings can get compensation. This means those without it should be able to pass on their higher costs to their customers.
Report co-author Paul Drummond, a senior research associate at UCL, tells Carbon Brief:
“Those electricity-intensive processes, businesses and sectors deemed at risk of international competition – and, thus, offshoring – are those that are eligible for compensation for EU ETS [EU emissions trading system] costs in the UK, Germany and France, as well as the CPS [carbon price floor] and renewable support costs in the UK only.”
Eligible firms got 85% compensation for carbon price costs during 2013-15, falling to 80% in 2016-18 and 75% in 2019-20. This includes indirect costs passed through by electricity suppliers. In the UK, some firms also get 85% compensation for the costs of renewable subsidies, while some German firms also get a discount at similar levels.
Today’s report divides policy costs into two sections. First, it shows that taxes and levies – including support for renewables – cannot explain higher prices in the UK. In fact, UK industrial electricity faces lower taxes and levies than in Germany or Italy, as the chart below shows.
Grubb tells Carbon Brief:
“UK industry, even without compensation, is paying less in taxes and levies than Italy or Germany. It’s significantly less. [So] it’s kind of nonsense, the idea that it’s driven by carbon-related policies.”
Carbon pricing – the second part of policy – is listed under “energy and supply” in the report. Here, policy is once again unable to explain lower costs on the continent. Even if the UK’s carbon price floor were set to zero, costs would be higher than in France or Germany, as the chart below shows.
If policy costs cannot explain the higher industrial electricity prices for uncompensated UK firms, then what other explanations can there be? As noted at the beginning of this article, while the CCC pointed to UK wholesale electricity prices and network costs, it did not explore why these differed.
However, the UCL report shows that network costs are actually almost equal across the four countries it looked at. Instead, it is the way these costs are shared between consumers that differs. In the UK, costs are shared relatively equally between domestic, business and industrial users whereas in Germany, France and Italy industry is cross-subsidised by smaller consumers.
This is one example of what the report calls a more “activist” approach to industrial policy on the continent. Another example is the French “Exeltium” consortium, a large group of industrial firms that negotiated a cheaper fixed-price, long-term electricity supply contract with French utility EDF. This sort of arrangement would be “incompatible” with the UK’s historic approach to promoting competition between industries, the report notes.
Besides these factors, it is in wholesale electricity prices where the largest and most obvious differences lie. These can be explained by the makeup of countries’ electricity mix and the past policy and investment decisions they stem from.
As the maps above show, Germany is more reliant on coal, for which prices fell sooner after 2012 than for gas. Part of its fleet uses lignite, a low-quality high-emissions coal that is cheap.
In contrast, the UK and Italy are reliant on international gas markets. Even if the UK were to develop a domestic shale gas industry – and even if it could extract gas as cheaply as in the US – this would be unlikely to cut UK gas prices, which are part of a larger, integrated European market.
Order of merit
Germany has also benefited from the merit-order effect, whereby renewables cut wholesale prices by pushing the most expensive generators out of the system.
— Simon Evans (@DrSimEvans) May 12, 2017
This cut German wholesale prices by €14-16 per megawatt hour (MWh) in 2016, the report says, with a similar saving in Italy, against a lower €7/MWh effect in the UK. These savings offset part of the policy costs discussed above.
For France, the wholesale price is low because it relies on nuclear plants built decades ago. The country also benefits, as does Germany, from being closely connected to the grids of neighbouring countries, whereas the UK and Italy are less integrated.
This explains one of the report’s recommendations, which is that the UK should continue to expand its interconnection capacity as planned, despite planning to leave the EU. This should help prices converge between the UK and the continent, as long as the UK maintains access to the EU’s internal energy market. (This remains a big if).
The other key recommendation of the report is for the UK to unlock investment in renewables, since this is now the cheapest way to generate electricity. New onshore windfarms, for example, could deliver electricity below current UK wholesale prices, if industry were to embrace them.
This directly contradicts the arguments of Timothy and others, who have argued on grounds of cost that the UK should slow climate policy, in general, and limit expansion of renewables, in particular.
The government should hold an auction for long-term “subsidy-free” contracts for such technologies, the report says, while looking at restrictive planning rules as part of a wider “full-scale” review of onshore renewables.
This could be combined with a renewed carbon price escalator, the report argues, along with continued cost exemption or compensation for heavy industry.
The government should also consider a more ambitious reform, whereby standardised power purchase agreements for renewables are bought and sold by industrial users in a “green power pool” that shares the system costs of backing up variable wind output.
Firms buying into this pool could get reduced rates by offering flexible demand to match variable supply. They would also avoid paying the rising carbon price, which would only be applied to trades on the wholesale electricity market.
Finally, the government could facilitate industry directly buying cheaper continental electricity via interconnectors, similar to systems already in place in Italy and California.
Overall, these proposed reforms, along with other changes already underway, offer a chance to bring UK industrial electricity prices in line with those on the continent, say the report’s authors.
“We present quite strong reasons why the UK is likely to converge to a large degree with continental prices. Our recommendations are really to accelerate and deepen that.”
Moreover, the conditions that make wholesale electricity in Germany and France cheaper than in the UK could soon evaporate.
Most of Germany’s coal fleet is old and will ultimately need to be replaced, though the debate on how or when to phase out coal is less advanced than in other countries. The country is also planning to close its remaining nuclear plants, which still supply a significant share of its mix. This will squeeze market supply and raise prices.
In addition, EU ETS carbon price rises in the wake of recent reforms would hit Germany particularly hard, given its reliance on coal-fired power.
For France, the country faces the costs of the life extensions needed to keep its ageing nuclear flee open for longer. This is an estimated €55bn, the report notes. Then there is the cost of decommissioning, estimated by utility EDF at €300m per gigawatt but widely expected to be higher.
In total, the UK could improve its relative position, but is unlikely to meet the government’s aim of having the lowest costs in Europe. Grubb tells Carbon Brief:
“My sense is that in the mid-term it’s reasonable for the UK to aim for mid-range – maybe even better than much of western Europe. But it is rather fantastic to imagine our prices could compete, for example, with Norway, or even some of central and east European countries, with both cheaper labour and [abundant] hydro.”
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