Electricity transmission and distribution

This briefing sheet aims to provide accurate and up to date information on electricity transmission and distribution in Great Britain.  

The national grid transfers power from around two dozen very large (≈2GW) power stations to the centres of demand in Great Britain’s conurbations.
The national grid transfers power from around two dozen very large (≈2GW) power stations to the centres of demand in Great Britain’s conurbations.

A General Description of Electricity Networks in Great Britain

Historic Context

From a widely disparate base where each municipality built its own power station starting around the 1890s, successive technology advances drove centralization through the establishment of the national grid, with economies of scale incentivising larger and larger power stations. There was a considerable variety in voltages and even frequencies, with direct current (DC) distribution surviving in some places into the 1970s. Standardisation was a big feature pre-war, and even bigger post-war, with the nationalisation of the industry. The industry was privatised in 1990, and deregulated to a degree, and this has resulted in an efficient industry – but one that until very recently was still running a national network not dissimilar to that of 1990.


Transmission essentially started in 1926 with the building of the 132kV national grid and the designation of the most efficient power stations to be connected to it and to be subject to central despatch based on their economic “merit order”. The significant growth in gross domestic product and electricity demand in the 1950s resulted in the creation of the Central Electricity Generating Board (CEGB ) and the building of the 400kV supergrid.

The CEGB had formal duties to ensure the sufficiency of electricity supplies and had responsibility for both investment in the fleet of generating stations and also in the transmission grid. The grid evolved into a highly effective method of transferring power from around two dozen very large (≈2GW) power stations to the centres of demand in Great Britain’s conurbations. Although subject to many small modifications, the basic topology of the supergrid has not changed much since the late 1970s.


Following the development of the national grid in the 1920s, the main role of distribution has been to transport electricity from the grid down through to end customers, generally via three voltage levels (33kV, 11kV and low voltage). There are currently approximately 25 million end customers in Great Britain. 

As with the transmission system, there was significant load growth in the 1950s and 1960s and much of today’s existing asset base stems from those years. The last 30 years have seen little overall load growth by comparison. However, it is expected that the decarbonisation of the heat and transport networks could lead to significant new growth in electrical demand by 2050. 

Before the 1983 Energy Act there was almost no generation connected to distribution networks. Although the landscape has changed dramatically, until the feed-in tariffs started to drive a growth in domestic photo-voltaic generation, the amount of generation connected to distribution networks only grew incrementally.


Distribution networks were generally designed with the power flow envisaged as always flowing down to end customers. Networks will of course work in both directions, transporting the output of generators. However, sometimes the basic historic design approach places limits on the amount of generation that can easily be connected.

Decarbonisation of heat and transport out to 2030 and beyond is likely to impose significant new loads on the overall electricity system, overturning three decades of relatively stable system peak loadings.

Energy Balance

All electricity transmission and distribution systems require that the generation and demand balance instantaneously in real time. Any imbalance will feed immediately into kinetic energy of the rotating masses in the system (i.e. generators and motors) and the system will either speed up or slow down. If this is not contained within very narrow tolerances, generators (and motors) will all overspeed and trip, or stall. In either case the consequences for the system and for customers will be very severe, i.e. probable total blackout.

One of National Grid’s key responsibilities is to manage this generation/demand balance. These responsibilities extend to forecasting national demand and generation from the long term, with appropriate increases in accuracy right down to real time.

The broad matching of supply and demand is done through the electricity trading market. Here, generators and energy suppliers trade energy in half hour blocks, with the suppliers (i.e. the retailers of energy to all end customers) having to contract with generators to obtain the energy they need for their customers in each half hour. The market operates to put strong incentives on generator and suppliers to both balance the market, and to deliver on their contracted positions. Clearly in real time there will be a mismatch between these contracted positions for all sorts of reasons. The trading stops 90 minutes ahead of real time (termed “gate closure”) and National Grid has the responsibility to ensure the balance from gate closure down to real time. National Grid achieves the balance by buying short term actions from generators, and also from larger demand customers, to ensure they can balance the system minute by minute.

Clearly there will be incidents that have to be managed. For example, the sudden and unexpected loss of a large generating set will create a sudden imbalance – to counteract this National Grid contract with other generators and large demand customers to carry power reserves that can be deployed automatically to rebalance the system.


Many renewable energy sources – wind, solar, tidal etc – cannot be scheduled or called upon directly to provide electricity like traditional fossil fuelled generation can. The growth of these generating technologies and the retirement of older coal and oil fired power stations gives rise to new challenges, particularly to National Grid in maintaining the minute by minute balance. However, although these renewable generators are not always controllable in real time, their output is predictable and there is usually some scope to reduce their output if required. For example, weather forecasting of wind and cloud cover is sufficiently accurate, certainly across the scale of Great Britain, so that National Grid can forecast the contribution from wind and solar at any one point in time.

Nevertheless, the total variability of renewable generation does make for increased volatility of the supply and demand balance compared to recent decades, and National Grid has to seek new services and ways of balancing the system. A key tool for this is buying response from larger demand industrial and commercial customers. For example, a large industrial customer is often able to drop part of its demand at very short notice to help balance an unexpected loss of generation from the system. Much work is going on to see how this useful approach, often called demand side response, can be extended to groups of smaller customers, where a small response from each can be aggregated to make a useful balancing action. It is expected that such aggregation might extend down to even domestic customers in the future – although it is expected that this could only be done both with customers’ explicit permission and via future “smart” domestic appliances.

Costs and Cost Recovery

Energy Trading


The electricity market in Great Britain is termed the British Electricity Trading and Transmission Arrangements (or BETTA). In BETTA, electricity suppliers contract with generators to purchase sufficient energy to supply all their customers. National Grid has a role in both operating the market, through its subsidiary company Elexon, and in trading in the market after gate closure, to ensure balancing the system in real time. National Grid achieves a real-time “balance” by buying and selling “balancing services”, many of which are procured through the “balancing mechanism”. The range of balancing services is broad, and includes the actions described above to buy short term actions from generators, demand consumers and aggregators to manage the overall energy balance, as well as the actions taken to manage power flows on the transmission networks.

Generators and suppliers pay National Grid and the Distribution Network Operators (DNOs) for the transport of energy through the wires, referred to as use of system charges. The generation, transmission, supply and distribution of electricity are all separately licensable activities and it is not possible to play one of the above roles in BETTA without a licence. Generation, transmission, supply and distribution are all exclusive licensed operations. It is illegal to undertake any of these activities without a licence.


The supply market is fully competitive. Customers can buy their energy from a number of suppliers – currently the “big six” and a number of smaller independent retailers. The supplier is the customer’s sole commercial contact with the energy supply chain. This model is called the supplier hub principle, and it is intended that the supplier is the key contact for arranging all services that customers need, including metering.

From the energy bill to end customers rendered by suppliers, the suppliers pay both National Grid and DNOs for use of system and for the costs of the energy as purchased from generators.

Customers’ sole contact and contract is via their supplier.

Network Costs

Costs for the transmission and distribution of electricity typically account for 16-20% of the typical domestic electricity bill. Both transmission and distribution charges are regulated by Ofgem and are set by methodologies related to the network assets used to supply each customer. These methodologies are explicitly approved by Ofgem.

The efficiency of networks has improved since privatisation and network costs are now only 60% of what they were at privatisation, in spite of significant increases in investment in the networks.

Future Challenges

Some of these have already been hinted at in the foregoing, but this section summarises the main challenges facing the electricity sector.

Decarbonisation of electricity generation

The growth of renewable generation brings issues of intermittency and forecasting, but also new challenges in that these technologies have significantly less mechanical inertia (in the case of wind turbines) or even none for all inverter connected generation such as photo voltaic solar cells.


National Grid is working with generators and distributors to develop cost-effective approaches to manage these new issues in a variety of industry forums and working groups.

Decarbonisation of heat and transport

As part of the Government’s mitigation of climate change risks, the legally binding targets for the decarbonisation of heat and transport assume the progressive move from fossil fuels to electricity generated from carbon free technologies. For heating, this means a move away from gas towards electricity – primarily heat pumps as these are a very efficient way of providing space heating. For transport, it is the growth of hybrid and battery vehicles. The Government’s projections are that this move to electricity for heating and transport will increase the demand on the nation’s electricity system by around 40-60% by 2050.


Nuclear is a low carbon generation technology, but clearly has its own engineering challenges. In terms of transmission and distribution system management, nuclear generation has been a challenge because the original (1950s) reactor designs were difficult and slow to flex up or down in response to changing requirements. As the mix of generation on the system tends more towards intermittent renewables, the historic inflexible nature of nuclear generation poses new challenges for National Grid in being able to balance the system.

A new fleet of nuclear generation is likely to come on stream from the early 2020s. Modern reactor design and technology mean that much greater flexibility should be available, although as with all things nuclear, flexible operating regimes will have to be explicitly addressed in the safety cases associated with each new reactor.


Although used for transmission at very high voltages over hundreds of kilometres, DC has not been used as a distribution technology for a century (even though some instances lingered around until the 1970s). However the emergence of renewable generation, the electronic converters it uses and the benefits of using storage with this sort of generation technology, has created a resurgence of interest in DC as a local distribution method. Currently there are exploratory trials being undertaken, although a significant return to DC stills seems remote.


Europe poses two future challenges to the arrangements in Great Britain, and both are linked. The first is the increase in interconnection capacity between Great Britain and other countries, and the second is the implementation of pan-European grid codes. 

Currently (as of late 2014) there are four interconnectors from Great Britain:

  • 2GW to France
  • 1GW to Netherlands
  • 500MW to Northern Ireland
  • 500MW to the Republic of Ireland

A fifth interconnector to Belgium is under consideration.

To harmonize a more interconnected Europe, the EU is rolling out a dozen grid code documents over the period 2014-17. These will be EU law and have direct effect in all EU countries. They will have significant effect on the electricity market and on the requirements placed on all who generate electricity (even down to domestic level) as well as new requirements on some users of electricity.

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