Electricity should be renewable and as local as possible

This post considers the proposition that most energy could be generated from renewables near to where it is needed. This article starts with a brief history of the electricity network, which reminds us that its origins were local in nature, and of how the grid evolved.

History of the electricity network

In 1881 the town of Godalming in Surrey established the first public electricity supply driven by a water wheel. This supplied street lighting and electricity to those that wanted it. In that year street lighting went out to tender and the cost of lighting by electricity was 19% cheaper than by gas.

In the late 19th Century a battled raged over whether we should be using alternating current(AC) or direct current (DC) for electricity distribution.

By 1900 many town councils were building power stations, which were typically fuelled by coal brought in by train. Over time these council power stations would be connected together to give greater flexibility, first using 2.2kV. Over the next 20 years a network at voltages 6.6, 11, 33 and 66kV developed. By the 1920s the network increased to 132kV. This meant that council generators could be replaced by larger regional stations.

In 1926 the Electricity Supply Act introduced effective national energy coordination. The Central Electricity Board was formed to concentrate the generation of electricity in a limited number of stations, which were inter-connected by a national grid by 1935.

Newton Abbot power station, built at Jetty Marsh in 1898, played its part in this development. It was bought by Torquay corporation in 1920, converted to AC, and used to provide power out to the coast. Newton Abbot power station developed to have a peak capacity of 52MW in 1948.

Newton Abbot Power Station 1949

In 1948 electricity supply was nationalised and eventually Newton Abbot power station was connected to the National Grid.

By the 1960s higher voltages (275kV and 400kV) started to overlay the grid with a supergrid. Nuclear stations started to appear placed near to the sea for cooling. Instead of transporting coal down to the south to generate electricity, electricity was generated by the coal fields and transmitted down south.

The Problem

Historically the transmission network developed because generation from coal was better placed near to mines than close to demand, because:

  • It was cheaper to transport electricity than to ship coal to cities.
  • Burning coal had caused caused serious atmospheric pollution including a smog that turned many building black.

The current development path for electricity generation and the electricity network involves placing a large amount of off-shore wind generation in remote locations, National Grid is planning to spend £54 billion to upgrade the transmission network to accommodate 50GW of off-shore wind energy.

Onshore wind and solar PV near to demand remain under exploited.

The alternative of much more local generation from solar and onshore wind backed by storage does not seem to have been seriously considered by government.

It appears that the network has evolved by patching up what already exists, each patch adding on expense and complication.

The network exists to supply electricity demand. So we need to ask if demand can be satisfied without so many expensive additions to the periphery of the network.

In an electricity network demand at any point in the network must be matched instantaneously by supply, if this does not occur the voltage and frequency will drop, which will cause issues for connected devices such as flickering lights. When a load switches on this increases demand on the electricity supply, which must either supply that demand from storage or generation. Currently all this supply to demand generation is handled centrally.

Now there is significant small scale generation connected at LV substations, this is currently seen as a problem to the network because it behaves in an unplanned manner. It should be seen as an opportunity to efficiently supply local demand. To do that at a local level there needs to be:

  • Storage so that:
    • over a day cycle at least supply and demand can be matched.
    • surges in demand are matched locally.
  • Smart systems so that:
    • Larger discretionary load (EVs, some heat pumps, water heating, appliances) run times can be timed to make best use of supply. Different user’s demands could be coordinated to avoid overloading the system.
    • Local supply and demand can be predicted, so that any additional supply from elsewhere in the network can be acquired in the most advantageous way (price, carbon intensity, availability of renewables could be considered).
    • Smart system would exist both on sites and at LV substations.

If there were sufficient solar and storage, such a scheme could work well in the summer (based on scaling up domestic experience). It would need onshore wind to continue operation through the winter, this may not be on the local LV network, but would probably be fairly close, so would need to be linked into systems at nearby LV substations as a preferred source of supply.

Only when there wasn’t enough local generation would it be necessary to procure electricity on the wider grid.

This may have significant costs at each substation, but bear in mind that there are 230,000 ground mounted substations in GB, and that National Grid intends to spend £54bn on upgrading the transmission network. This is equivalent to £234,000 per substation.

It is at least theoretically possible to meet the UK’s electricity demand using:

  • Renewable generation – mainly wind and solar, but also other technologies as these develop.
  • Storage of various durations including batteries, pumped hydro.
  • A relatively small amount of dispatchable generation (green hydrogen, biofuel generation, etc.)

This has been demonstrated by CAT and REGEN studies.

Consequences of carrying on as we are

Cost of upgrading the transmission network for 50Gw of offshore wind

According to carbon brief National Grid ESO plans to spend £54bn upgrading the transmission network to be capable of carrying 50Gw of offshore wind planned for 2030. When the wind blows it seems plausible that SW demand could be met by off-shore wind from the north sea. This is equivalent to £234k per ground mounted LV substation (assuming 230k ground mounted LV substations). Also £2k per property

Most of the electricity consumed in the South West is not generated in the South West

Most of the time the majority of electricity demand is met by generation outside the South West.

Source: WPD Live data feed

Normally electricity demand peaks between 4pm and 7pm and is at its lowest overnight, and most of the time local generation is much less than demand. On sunny days PV generation is significant, but still not enough to meet demand.

It is expected that by 2030 electricity demand will have increased substantially due to electric vehicles and electric heating.

Does Grid demand need to increase

Conventional thinking says that electricity demand will double because of electrification of transport and heat.

This would not be the case if:

  • The standard of insulation of all buildings were improved substantially
  • Private vehicle use were to be reduced, in favour of active transport and public transport.
  • Lightweight electric vehicles such as e-bike, e-scooters were to be used more.

Enabling Technologies

Renewable energy is the cheapest energy source

Why did renewables become so cheap so fast? from Our World in Data studies the fall in the cost of wind and solar between 2009 and 2019, and suggests possible causes. They found that the cost of electricity generation from solar dropped by 89%, and on-shore wind by 70%. A similar thing has happened with off-shore wind, but not with nuclear.

This rapid cost reduction for renewables has resulted in electricity from gas costing roughly 4 times as much a from renewables, following recent gas price rises.

50% of electricity demand could be met by solar PV on commercial roofs

According to Solar PV on commercial buildings, a 2016 report from BRE: “There is an estimated 250,000 hectares of south facing commercial roof space in the UK. If utilised this could provide approximately 50% of the UK’s electricity demand.”

In practice 50% is probably an over estimate because this much solar is unlikely to be timed to match demand, however, it should when combined with storage to make most buildings self sufficient for the summer.

Teignbridge has many existing buildings without solar, though recent applications for new commercial buildings have often incorporated substantially more solar photovoltaics than is required by the building regulations.

A case in point is the recent application by Lidl to build a store in Bovey Tracey. According to the carbon reduction plan submitted as part of the application, the roof will have 180kWp of solar panels, which reduces the building’s regulated emissions from 111tonnes of CO2 equivalent to just 4 tonnes. We can expect other examples to come forward following energy price rises.

With sufficient panels and storage it should be possible on many sites to be almost self-sufficient between March and September.

Teignbridge’s draft local plan identifies 217GWh of on-shore wind capacity

Teignbridge’s draft local plan identifies 217GWh of on-shore wind capacity, which is about 39% of current demand. We think that 217GWh is a low estimate.

Public Opinion on Renewables

A recent opinion poll by survation shows that there is overwhelming public support for building new wind and solar farms to tackle the cost of energy crisis.

Another poll also from survation shows that both the public and conservative voters believe windfall tax on energy producers should form a part of paying for energy bill cap.


Another essential component of a locally based solution is sufficient storage. This would be used for:

  • Storing solar energy during the day to use at night, this would often be for use on domestic or commercial sites where it had been collected.
  • Storing of local wind energy when it abundant for later use, it is possible that when local wind is abundant it would also be relatively cheap.
  • Network management purposes, such as short term balancing.
  • Longer term storage to survive longer shortages.

DNO operating licence prevents them from owning storage, so grid connected storage at substations would require another operator.

LV substations

Most sites connect to an LV electricity station, which then connects to the distribution network. The capacity of a substation and the distribution network it connects to is limited, if demand and local generation can be managed to within this limit then there will be no need to upgrade the substation or distribution network.

Accurately managing power at a substation level requires substation metering and intelligence at the substation, this would be relatively low cost, but most substations currently have very little monitoring.

Larger demands could be accommodated when there they are matched by local generation. Storage either at substations or behind the meter also helps maintain the balance, both by storing excess local generation, and charging during periods of low demand and excess external generation.

Demand Management

Demand from things like EV charging, heating water, running storage heaters (and heat pumps in suitable houses), as well as appliances such as washing machines and dishwashers can be shifted provided that demand is satisfied within some time window. If you have solar PV and you choose to do the washing when the PV is exporting, this is a kind of demand management.

This concept can be extended to networked grid connected devices, which can register that they require an amount of energy by a certain time, the grid then works out when it is going to supply the energy.


The OpenADR Alliance was created to standardize, automate, and simplify Demand Response (DR) and Distributed Energy Resources (DER) to enable utilities and aggregators to cost-effectively manage growing energy demand & decentralized energy production, and customers to control their energy future. OpenADR is an open, highly secure, and two-way information exchange model and Smart Grid standard. Together we are creating the future of smart grid modernization today.

OpenADR – Article on BSi adoption of OpenADR 2.0BSi have published two standards based on OpenADR:

PAS 1878:2021 Energy smart appliances. System functionality and architecture – Specification

PAS 1879:2021 Energy smart appliances. Demand side response operation – Code of practice


It may not always be possible for individual premises to have the most advantageous combination of on-site renewables and storage. There could be economies in installing a wind turbine, sharing rooftop solar between several premises in the same building, or sharing a large ground mounted solar setup. As soon as the grid is used to connect to a larger resource, grid charges are involved.

A microgrid consists of several sites which are connected together, share common resources and a single (probably smaller) grid connection.

Most of the time electricity comes from on-site resources.

When on-site resources are insufficient, or it is otherwise advantageous to do so, the microgrid will draw on the grid, and either distribute electricity to members, or store it for later use.

A microgrid could be a group of dwellings or a business park.

Microgrids are only really feasible when building from scratch, new estates or new developments, where renewable energy and storage can be shared. There are significant operational issues beyond construction.

A virtual microgrid could exist at an LV substation, if a number of connected sites were to aggregate their supplies. This means the operation and maintenence remains with the DNO, but a community can share resources such as renewables or storage.

What about Inertia, Black start, Power factor correction and so on

It is sometimes claimed that a grid consisting entirely of renewables will be unstable, and unable to start if it is ever shut down. You will often hear terms like inertia and black start used in this context.

Conventional generator have a spinning turbine, which tends to carry on spinning at the same rate when power is removed because of Inertia. Whereas solar PV and wind turbines use inverters to generate alternating current (AC) to put into the grid. Normally inverters are grid tied, which mean that they depend on the presence of AC to produce alternating current. Grid-forming inverters on the other hand will produce AC based on a local signal source.

Intertia without the spin

This article gives a good description with video of Inertia and related concepts, and describes how a grid powered entirely by renewables can work with Grid-Forming inverters. New large renewable generators connecting in Texas have been required to do this for some time.


ZCB is a study from Centre for Alternative Technology, which amongst other things models how the UK could be powered by renewables, including 84% of the time with wind and/or solar. They based this study on 10 years of weather data at half hour resolution.

A day in the life 2035

A day in the life 2035 is a detailed modelling study by REGEN and National Grid ESO of a dull windless winter day, and how the grid would cope.


On site generation

Firstly there is a lot of scope still for generation on sites where electricity is required, which would avoid any change in grid capacity. This could lead to many sites being self-sufficient for a significant part of the time.

A typical site would need:

  • Renewable generation in the form of rooftop solar, and for larger sites smaller wind turbines
  • Storage sufficient to ensure 24 hour power on good generation days, possibly longer.
  • Energy management system to handle scheduling of larger loads (EV charging, Heat Pumps, Water Heating, Appliances)

LV Substation

Key to all this is a smart local network, which would have:

  • Sufficient storage to deal with demand fluctuations and to store electricity procured from outside advantageously (either in terms of price, carbon intensity or renewable availability)
  • Smart system which monitored system performance, and negotiated supply of larger loads with connected sites.

The LV substation would be able to fairly accurately predict the load that would be placed on the higher voltage network, and would be able to draw down supply when it was available. This would lead to a much more stable situation for the higher voltage network, which could then dispense with many of the patches that it currently has.

It may also mean that much less reinforcement would be needed to the higher voltage network.



Ofgem currently has a policy of being technology neutral, prioritising what it sees as the best value, regardless of climate concerns.

Government is generally technology agnostic, rather than prioritising renewables.


Designated areas more difficult for renewables

Commercial scale renewables such as wind and solar farms are not allowed in National Parks.

In the National Park, conservation areas and on listed buildings renewable technologies generally require planning permission. Planning permission is determined by the aesthetic effect that the renewable installation has on the area. This means that it is unlikely that permission would be granted for:

  • Standard monocrystalline silicon panels facing a road
  • Horizontal axis wind turbines

Permission is more likely if the renewable installation is out of public view, or is designed to fit in with the street scene. This could be by using things like solar slates.

If you live in Dartmoor National Park (DNPA) and want to fit renewable technologies to your property, then you should seek planning advice from the park planners.

National Planning Policy Framework (NPPF)

The following is a copy of the paragraphs that have effectively stopped planning applications for onshore wind.

  1. When determining planning applications for renewable and low carbon
    development, local planning authorities should:
    a) not require applicants to demonstrate the overall need for renewable or low
    carbon energy, and recognise that even small-scale projects provide a valuable
    contribution to cutting greenhouse gas emissions; and
    b) approve the application if its impacts are (or can be made) acceptable54. Once
    suitable areas for renewable and low carbon energy have been identified in
    plans, local planning authorities should expect subsequent applications for
    commercial scale projects outside these areas to demonstrate that the
    proposed location meets the criteria used in identifying suitable areas.

Note 54:

54 Except for applications for the repowering of existing wind turbines, a proposed wind energy development involving one or more turbines should not be considered acceptable unless it is in an area identified as suitable for wind energy development in the development plan; and, following consultation, it can be demonstrated that the planning impacts identified by the affected local community have been fully addressed and the proposal has their backing.

This has effectively stopped new applications for onshore wind since 2016

In the recent fiscal event there is the following statement:

“The Growth Plan also announces further sector specific changes to accelerate delivery of infrastructure, including:

· prioritising the delivery of National Policy Statements for energy, water resources and national networks, and of a cross-government action plan for reform of the Nationally Significant Infrastructure planning system

bringing onshore wind planning policy in line with other infrastructure to allow it to be deployed more easily in England” (pg 21)

Spot the wind turbine! – industrial scene in the Netherlands.


Cost of connecting to the distribution network

The cost of connecting to the network often rules projects out.

Making a connection with generation capacity no more than 16A in capacity accompanied with no more than 16A of connected storage can be done without first informing the DNO, the DNO needs to be informed afterwards with a G98 notification.

Any larger connection requires a G99 application, which needs to be approved by the DNO. Not only does this take time, there is a strong probability that at present the DNO will ask for payment for network upgrades, which could be not just at the current voltage, but at up to 2 higher voltages. It is not uncommon for this payment request to be £10k for an additional 5kW system.

Most projects are effectively limited to this size because the installer doesn’t want the overhead of making a G99 application. I believe that this has limited the deployment of rooftop PV.

A review called the Significant Code Review is currently being undertaken by Ofgem, which proposes that network upgrades be planned for by the DNO and most of the cost absorbed in network charges. Costs local specific to connecting to a site would still be born by the site, but otherwise costs would be limited to the current voltage, and should generally be much lower.


Presentation on Ofgem proposals for a Significant Code Review (SCR), which will encourage DNOs to plan for increased network demand, and limit the lottery of charges for upgrades falling on the first customer to trigger an upgrade.

Delay getting a connection

There are currently delays of up to 10 years getting a network connection above 1MW, this is severely delaying larger renewable projects.

Regen calls for urgent action on grid connections

“1MW seeking to connect to the distribution network are facing delays of up to a decade”



Intertia without the spin

Good description with video of Inertia and related concepts, and describes how a grid powered entirely by renewables can work with Grid-Forming inverters. New large renewable generators connecting in Texas have been required to do this for some time.


Accounting for renewables

Currently electricity suppliers reconcile their generation on an annual basis, which means that it is possible to buy certificates (REGOs) for 100% renewable generation without actually buying anywhere near 100% renewable generation. This has lead most retail electricity suppliers to claim 100% renewable electricity.

Once generated electricity enters the network it contributes to the general carbon intensity of the network, it becomes unidentifiable. It would require physically separate supplies to guarantee renewable supply, which would not be practical. For most practical purposes a similar result could be achieved if electricity were accounted for in half-hour periods as recorded by smart meters. This would enable the consumer to identify the carbon intensity of each unit consumed. It would also enable suppliers claims of renewable percentages to be more credible.

The EnergyTag project seeks international agreement on a standard for generating hourly certificates for energy generation.

Selling locally generated electricity:

Local Electricity Bill seeks to enable selling of electricity locally by a generator directly without selling to an intermediate licensed electricity supplier.

Energy Local

Ripple Energy

Octopus fan club


Smart grid

A Smart grid is needed to ensure that local generation and demand are balanced, and that any difference is exported or imported from the wider grid as needed.

Why are electricity prices rising?

We examine the reasons behind the dramatic rises in electricity prices following the unprecedented rises in fossil fuel prices, and why reductions in renewable prices have had no effect.

We examine the reasons behind the dramatic rises in electricity prices following the unprecedented rises in fossil fuel prices, and why reductions in renewable prices have had no effect.

Fossil fuel prices have risen dramatically since 2021 and particularly since May 2022. The price of gas and oil in particular has soared. Gas is still used for a large part of electricity generation, as well as directly for heating. Because of the way the wholesale electricity market works, the price of gas normally sets the price of electricity.

See Ofgem for current information on wholesale prices

How the wholesale electricity market works (simplified)

Electricity retailers pay the wholesale price for electricity they sell on to retail customers. The electricity demand in any period needs to be balanced to generation. This balancing is done by a bidding process where generators bid to generate in a period. The Electricity System Operator (ESO) ranks the bids in merit order with the lowest price first, and then adds up the generation capacity until a marginal generator is found. The price paid to all successful bidders is the price paid by the marginal generator. Recently the marginal bidder has often been a gas generator.

For a more detailed explanation

Forecasts for the price cap

Domestic customers on standard variable tariffs are protected from excessive charging by a price cap, which is calculated periodically by Ofgem based on predictions of market prices for the upcoming period. In April 2022 the price cap rose sharply to 28p per unit for electricity, and in October 2022 it will rise to 52p. Consultancy Cornwall Insight predicts that the cap will rise a further 51% at the start of January to about 80p per unit, and a further 13% in April to about 90p per unit.

Ofgem cap methodology change

Historically Ofgem calculated the cap six monthly, based on forward prices wholesale price estimates. Recently wholesale prices have been volatile, and suppliers have had to pay more for electricity than was predicted. In order to avoid further supplier failures, Ofgem have introduced some changes:

  • The cap will be recalculated at 3 monthly intervals from October onwards.
  • A backwardisation calculation has been introduced which introduces compensation for the excess of actual wholesale prices for the previous period over those predicted in advance of the period.

These changes compensate suppliers for additional costs they have incurred and have the effect of increasing the cap more than would otherwise have been the case.

Energy Price Guarantee

Since this post was written the government has announced an energy price guarantee, which replaces the energy cap. This means that effectively the cap on electricity prices will be 34p.

For further about this announcement are here.

Some help for businesses has also been promised.

You might have thought that the simple measure of boosting onshore renewables would have been an obvious step to shorten the period that the government had to finance this intervention. The government hasn’t done this, instead it is lifting the ban on fracking, launching a new round of oil and gas licencing, and carrying on with nuclear projects. None of these actions will make any difference in the next few years to energy prices, but they will certainly cause increased carbon emissions.


Most domestic electricity customers expect to buy electricity at a fixed price per unit, very few would accept a tariff which offered a different price for each half hour period (to the author’s knowledge there is only one such tariff). This means that electricity retailers need to find a means of fixing the price of the electricity they offer for the period of the contracts they offer, to do this they buy contracts to supply electricity at an agreed price at a future date. This practice is known as hedging. The failure of a many smaller suppliers to hedge adequately in 2021 lead to the large number of supplier failures last year.

The cost of renewables

Between 2009 and 2019 the price of electricity from solar generation dropped by 89%, and the price of on-shore wind dropped by 70%. A similar thing has happened with off-shore wind.

A similar thing has not happened with Nuclear.

Why did renewables come so cheap so fast? discusses the price drop in more detail.

This rapid cost reduction for renewables has resulted in electricity from gas costs roughly 4 times as much as from renewables.

Renewables have a high initial capital cost and low running costs. Initially subsidies were required to get the market established and get the benefits of scale. There is significant future price risk if renewables were to be funded based on future receipts, the cost of capital is substantially reduced if this risk is mitigated somehow.

Support methods for renewables

Early renewables were subsidised by the Renewables Obligation (RO) and Feed In Tariff (FIT), which are currently paid out of retail electricity bills. More recently renewables have been financed by Contracts for Difference (CfD), which now tend to reduce electricity prices. All domestic renewables are now privately funded. Given current prices some grid scale renewables are also being funded without subsidy.

Renewables Obligation

The RO requires electricity suppliers to buy a proportion of Renewables Obligation Certificates (ROCs) from generators registered with the RO scheme. ROCs are issued by Ofgem to registered generators. There is a monthly reconciliation to ensure that suppliers have either bought enough certificates or pay a penalty known as the buy-out price.

For further information see https://www.edie.net/edie-explains-renewables-obligation-certificates-rocs/

RO closed to new generators in 2017, but will continue to operate until 2037.

Each year BEIS calculates the amount of ROCs that need to be issued to meet proportions of renewables fixed in the 2015 Renewables Obligation Order (ROO). For 2022-3 the number of ROCs is set at 124.5 million. From this a rate of 0.491 ROCs per MWh is set for GB, this is a drop from 0.492 in 2021-2.

Projects remain in the RO scheme for 20 years, the scheme started in 2002 and closed in 2017, so we expect to see the number of generators in the scheme falling from now on, so the number of ROCs required will also drop.

ROCs are traded in the market, and are normally sold above the buy-out price set by Ofgem. Suppliers are prepared to do this because they receive a share of the buy-out money in addition to meeting their obligation.

The buy-out price is set by Ofgem each year by rules determined by the ROO and is linked to RPI. For 2022/3 it is set at £52.88/MWh

Feed In Tariff

Feed in Tariff is paid to domestic generators and smaller grid scale generators. It is paid regardless of how the electricity generated is consumed. The rate paid depends on when the scheme was joined and is inflation linked. The last FIT installations were done in 2019, though the rate was far lower than early installations in 2011.

Electricity generated under FIT must be measured by a generation meter. In December 2021 Ofgem published rules that must be applied when FIT registered plant is replaced or modified, essentially:

  • If the generation capacity is increased, then the meter reading is adjusted pro-rata when calculating the amount of FIT payable.
  • If storage is installed behind the generation meter, then it must not be possible for electricity to pass from the grid side of the meter to the generator side of the meter. (Otherwise it would measure electricity that hadn’t been generated by the plant).

For further information see Ofgem ruling.

Contracts for Difference

New renewables are supported by Contracts for Difference (CfD). Periodically there is a CfD auction where generators bid a strike price for the period of the contract. For each technology the auction is for an amount of generation. The result of the auction is a strike price for each technology. If the wholesale price does not meet the strike price then generator is subsidised from electricity bills. If the wholesale price exceeds the strike price, then the generator compensates electricity bills.

This subsidy is managed by a government owned company—the Low Carbon Company. 

In recent CfD auctions prices have fallen, and record amounts of renewables have been contracted.

Since the end of 2021 the electricity wholesale price has mainly been above the strike price, so CfD has acted to reduce electricity bills. In a climate of higher wholesale prices this will continue.

See Low Carbon Contracts Company Historic Dashboard for payments for recent data.

Other electricity charges

As well as wholesale electricity costs, retail electricity bills also pay for network costs, social and environmental obligations, other direct costs, taxes and operator’s margin.

Environmental and Social costs aka Green Levies.

Environmental and Social costs are often referred to as ‘Green Levies’ and currently amount to about 12% of electricity bills. The breakdown of environmental and social charges is shown on the left.

RO and FIT schemes have now both ended, so the amount of generation in the scheme won’t increase and will start to fall, but payments are linked to RPI, so the costs will increase. These are both contractual agreements.

ECO and WHD assist those in fuel poverty to improve the insulation standards of their dwellings.

Figures derived from Energy bills: getting the balance right

Cost of failed suppliers

When a supplier fails another supplier is found to continue their supply. Other costs associated with the failure are shared between the remaining suppliers, who pass this on via electricity bills. This has resulted in a near doubling of standing charges for electricity this year. According to this article the cost of failed suppliers is estimated at more than £2.7bn.


The electricity market has grown to be very complex, this brief note doesn’t touch on many aspects of it. As with many things that have grown complex there is a temptation to think that it would be simpler to start again, if this is done it should be done with care.

BEIS has launched a consultation Review of Electricity Market Arrangements (REMA), which runs until October. This is far reaching, recognises some of the current problems, and could eventually achieve a more workable market, however, it is unlikely there would be any change from this for several years.

Council’s carbon reduction targets won’t do the job

Following its Climate Emergency declaration three years ago, Teignbridge District Council has published and adopted Part 1 of its Climate Action Plan. Part 2 is expected later this year.

Action on Climate in Teignbridge (ACT) welcomes the long-awaited plan, believing it is an essential first step in delivering on the council’s commitment to be a carbon neutral district by 2025. It is excellent to see standards set, but ACT has concerns that the emission reduction targets included in the plan are based on outdated data and will not make the difference we need to see.

Part 1 of the plan sets out how the council expects to reduce carbon emissions in its own sphere, in things it owns, purchases, funds and supplies. Part 2 will cover the wider district, including transport, housing, businesses, land use, energy and infrastructure.

The plan includes 39 actions, four policies and 11 targets. ACT has no major problem with the actions or policies. It is primarily the targets that need further work.

Carbon emission targets are set by reference to a carbon budget. The budget sets a limit on the cumulative amount of greenhouse gases an organisation, a country or the world can emit that gives a significant chance of limiting global warming to 1.5C above pre-industrial temperatures. It is like a financial budget, where you set yourself weekly or monthly spending limits so you don’t go overdrawn.

In the case of carbon budgets, the limits are how much carbon can be emitted over a time period, to make sure we don’t trigger runaway climate change. We can’t afford the equivalent of an overdraft when it comes to the climate!

Carbon budgets have to be adjusted as the average global temperature rises and to take account of whether targeted emission reductions have been achieved. Global warming has now reached 1.2C and we are on track to reach 1.5C by the early 2030s, if not earlier. The tighter the budget, the more likely we are to limit global warming.

The Teignbridge plan states that the council aims to limit its cumulative emissions “to levels consistent with 1.5°C and well below 2.0°C of global warming”. This needs revising as, at the COP26 climate meeting held in Glasgow last year, governments agreed to make 1.5C the firm limit to aim for, due to the risks of allowing any further warming.

The basis for setting the council’s carbon budget also needs revision, as the budget calculation uses data from a 2018 study. That doesn’t sound too out of date, but there has been a significant rise in average global temperature since then. Moreover, setting targets for emission reductions based on this budget means they fall well below the UK government’s legal requirements.

ACT believes the council should use the government’s statutory carbon budget to set its targets. It would be even better if it used the Paris Agreement targets, as ACT has proposed.

There is a big difference between these various targets. The annual emission reductions required under the Paris Agreement (for a likely, or 67% chance of staying within 1.5C) are 10.4% year on year. To meet the UK’s statutory requirements (for a 50/50 chance), they are 7.9% year on year. The Teignbridge plan targets are based on a study that recommends a minimum carbon reduction of 4.2% flat rate.

There is another issue: the targets only include the council’s direct emissions. These are mainly from heating council buildings and fuel used in the council vehicle fleet. These are known as scope 1 and scope 2 emissions, and only account for about one-third of the council’s annual emissions. The bulk of the emissions, known as scope 3, are indirect, from stuff the council buys, mainly for building work and services they buy in.

The plan does have ambitions to influence the council’s suppliers with regard to scope 3 emissions, but they are not included in the targets.

Finally, while most of the 39 actions in the plan are good, some excellent, there is no indication of the expected emissions reduction for each action, or the timescale involved. ACT believes this should be addressed as soon as possible, and that a regular review of progress against the expected reduction for each action should also be part of the plan.

Teignbridge District Council still has work to do on its Carbon Action Plan.