National Grid (Great Britain)

National Grid (Great Britain)
400 kV power line in Cheshire

The National Grid is the high-voltage electric power transmission network in Great Britain, connecting power stations and major substations and ensuring that electricity generated anywhere in England, Scotland and Wales can be used to satisfy demand elsewhere. There are also undersea interconnections to northern France (HVDC Cross-Channel), Northern Ireland (HVDC Moyle), the Isle of Man (Isle of Man to England Interconnector) and the Netherlands (BritNed).

On the breakup of the Central Electricity Generating Board in 1990, the ownership and operation of the National Grid in England and Wales passed to National Grid Company plc, later to become National Grid Transco and now National Grid plc. In Scotland the grid is owned by Scottish Power and Scottish and Southern Energy.



At the end of the 19th century, Nikola Tesla established the principles of three-phase high-voltage electrical power distribution while he was working for Westinghouse in the United States. The first to use this system in the United Kingdom was Charles Merz, of the Merz & McLellan consulting partnership, at his Neptune Bank Power Station near Newcastle upon Tyne. This opened in 1901,[1] and by 1912 had developed into the largest integrated power system in Europe.[2] The rest of the country, however, continued to use a patchwork of small supply networks.

In 1925, the British government asked Lord Weir, a Glaswegian industrialist, to solve the problem of Britain's inefficient and fragmented electricity supply industry. Weir consulted Merz, and the result was the Electricity (Supply) Act 1926, which recommended that a "national gridiron" supply system be created.[3] The 1926 Act created the Central Electricity Board, which set up the UK's first synchronised, nationwide AC grid, running at 132 kV, 50 Hz. It began operating in 1933 as a series of regional grids with auxiliary interconnections for emergency use. Following the unauthorised but successful short term paralleling of all regional grids, by the night time engineers in around 1937, by 1938 the grid was operating as a national system. The grid was nationalised by the Electricity Act 1947, which also created the British Electricity Authority.

In 1949, the British Electricity Authority decided to upgrade the grid by adding 275 kV links. From 1965, the grid was partly upgraded to 400 kV, beginning with a 150-mile (241 km) line from Sundon to West Burton, to become the Supergrid.

In the most recent issue of the code that governs the British Grid, the Grid Code [4] , the Supergrid is defined as referring to those parts of the British electricity transmission system that are connected at voltages in excess of 200 kV (200,000 volts). British power system planners and operational staff therefore invariably speak of the Supergrid in this context; in practice the definition used captures all of the infrastructure owned by the National Grid company in England and Wales, and (in England and Wales) no other equipment.

Grid description

Network size

The following figures are taken from the 2005 Seven Year Statement (SYS)[5]

  • Maximum demand (2005/6): 63 GW (approx.) (81.39% of capacity)
  • Annual electrical energy used in the UK is around 360 TWh (1.3 EJ)
  • Capacity (2005/6): 79.9 GW (or 80 GW per the 2008 Seven Year Statement)[6]
  • Number of large power stations: 181
  • Length of 400 kV grid: 11,500 km (circuit)
  • Length of 275 kV grid: 9,800 km (circuit)
  • Length of 132 kV (or lower) grid; 5,250 km (circuit)


Figures are again from the 2005 SYS.

  • Joule heating in cables: 857.8 MW
  • Fixed losses: 266 MW (consists of corona and iron losses; can be 100 MW higher in adverse weather)
  • Substation transformer heating losses: 142.4 MW
  • Generator transformer heating losses: 157.3 MW
  • Total losses: 1,423.5 MW (2.29% of peak demand)

Although overall losses in the national grid are low, there are significant further losses in onward electricity distribution to the consumer, causing a total distribution loss of about 7.7%.[7] However losses differ significantly for customers connected at different voltages; connected at high voltage the total losses are about 2.6%, at medium voltage 6.4% and at low voltage 12.2%.[8]

Power flow

There is an average power flow of about 11 GW from the north of the UK, particularly from Scotland and northern England, to the south of the UK across the grid. This flow is anticipated to grow to about 12 GW by 2014.[9]

Because of the power loss associated with this north to south flow, the effectiveness and efficiency of new generation capacity is significantly affected by its location. For example new generating capacity on the south coast has about 12% greater effectiveness due to reduced transmission system power losses compared to new generating capacity in north England, and about 20% greater effectiveness than northern Scotland.[10]

Reserve services and frequency response

National Grid is responsible for contracting short term generating provision to cover demand prediction errors and sudden failures at power stations. This covers a few hours of operation giving time for market contracts to be established to cover longer term balancing.

Frequency-response reserve acts to keep the system AC frequency within 1% of 50 Hz, except in exceptional circumstances. This acts on a second by second basis to adjust demand and provide some extra generation.[11]

Reserve services are a range of services on differing response times:[11]

  • Fast Reserve: rapid delivery within two minutes of increased generation or reduced demand, sustained for a minimum of 15 minutes.
  • Fast Start: units that start from standstill to deliver power within five minutes automatically, or seven minutes of a manual instruction, maintained for a minimum of four hours.
  • Demand Management: reduction of demand of at least 25MW from large users of power, for at least an hour.
  • Short Term Operating Reserve (STOR): generation of at least 3MW, from a single or aggregation of sites, within four hours of instruction and maintained for at least two hours.
  • BM Start-Up: mainstream major generation units maintained in either an energy readiness or hot standby state.

These reserves are sized according to three factors:[12]

  • The largest credible single generation failure, which is currently either Sizewell B nuclear power station (1,260 MW) or one cable of the HVDC Cross-Channel interconnector (1,000 MW)
  • The general anticipated availability of all generation plants
  • Anticipated demand prediction errors

Control of the grid

The National Grid is controlled from the National Grid Control Centre which is located in St Catherine's Lodge, Sindlesham, Wokingham in Berkshire in South East England.51°24′53″N 0°52′36″W / 51.414676°N 0.876615°W / 51.414676; -0.876615 [13][14][15]

Transmission costs

The costs of operating the National Grid System are recouped by National Grid Electricity Transmission plc (NGET) through levying of Transmission Network Use of System (TNUoS) charges on the users of the system. The costs are split between the generators and the users of electricity.[16]

Tariffs are set annually by NGET, and are zonal in nature—that is, the country is divided up into different zones, each with a different tariff for generation and consumption. In general, tariffs are higher for generators in the north and consumers in the south. This is representative of the fact that there is currently a north-south flow of electricity, and the additional stresses on the system increasing demand in areas of currently high demand causes.

Triad demand

Triad demand is measured as the average demand on the system over three half hours between November and February (inclusive) in a financial year. These three half hours comprise the half hour of system demand peak and the two other half hours of highest system demand which are separated from system demand peak and each other by at least ten days.

These half hours of peak demand are usually referred to as Triads.

In April of each year, each licensed electricity supplier (such as Centrica, BGB, etc.) is charged a fee for the peak load it imposed on the grid during those three half hours of the previous winter. Exact charges vary depending on the distance from the centre of the network, but in the South West it is £21,000/MW for one year, or £7,000/MW for each of the three half hours, for convenience assuming they were identical (which is unlikely; however, they will be close). The average for the whole country is about £15,000/MW·year. This is a means for National Grid to recover it charges, and to impose an incentive on users to minimise consumption at peak, thereby easing the need for investment in the system. It is estimated that these charges reduced peak load by about 1 GW out of say 57 GW.

This is the main source of income which National Grid uses to cover its costs and these charges are commonly also known as Transmission Network Use of System charges (TNUoS). (Note this is for high voltage long distance transmission and the lower voltage distribution is charged separately.) The grid also charges an annual fee to cover the cost of generators, distribution networks and large industrial users connecting.

These Triad charges encourage users to cut load at peak periods; this is often done using diesel generators. Such generators are also routinely used by National Grid.[17]

Estimating costs per kWh of transmission

If the total TNUoS or Triad receipts (say £15,000/MW·year × 50,000 MW = £750 million/year) is divided by the total number of units delivered by the UK generating system in a year (the total number of units sold – say 360 terawatt-hours (1.3 EJ).[18]), then a crude estimate can be made of transmission costs, and one gets the figure of around 0.2p/kWh. Other estimates also give a figure of 0.2p/kWh.[19]

However, Bernard Quigg notes: "According to the 06/07 annual accounts for NGC UK transmission, NGC carried 350TWh for an income of £2012m in 2007, i. e. NGC receives 0.66p per kW hour. With two years inflation to 2008/9, say 0.71p per kWh.",[20] but this also includes generators' connection fees.

Generation charges

In order to be allowed to supply electricity to the transmission system, generators must be licensed (by DECC) and enter into a connection agreement with NGET which also grants Transmission Entry Capacity (TEC). Generators contribute to the costs of running the system by paying for TEC, at the generation TNUoS tariffs set by NGET. This is charged on a maximum-capacity basis. In other words, a generator with 100 MW of TEC who only generated at a maximum rate of 75 MW during the year would still be charged for the full 100 MW of TEC.

In some cases, there are negative TNUoS tariffs. These generators are paid a sum based on their peak net supply over three proving runs over the course of the year. This represents the reduction in costs caused by having a generator so close to the centre of demand of the country.

Demand charges

Consumers of electricity are split into two categories: half-hourly metered (HH) and non-half-hourly metered (NHH). Customers whose peak demand is sufficiently high are obliged to have a HH meter, which, in effect, takes a meter reading every 30 minutes. The rates at which charges are levied on these customers' electricity suppliers therefore varies 17,520 times a (non-leap-) year.

The TNUoS charges for a HH metered customer are based on their demand during three half hour periods of greatest demand between November and February, known as the Triad. Due to the nature of electricity demand in the UK, the three Triad periods always fall in the early evening, and must be separated by at least ten clear working days. The TNUoS charges for a HH customer are simply their demand during the triad periods multiplied by the tariff for their zone. Therefore (as of 2007) a customer in London with a 1 MW cumulative demand during the three triad periods would pay £19,430 in TNUoS charges.

TNUoS charges levied on NHH metered customers are much simpler. A supplier is charged for the sum of their total consumption between 16:00 and 19:00 every day over a year, multiplied by the relevant tariff.

Major incidents

Power cuts due to either problems on the actual infrastructure of the supergrid (defined in the Grid Code, as the transmission system operated by National Grid, which in England and Wales, comprises lines energised at 275,000 volts and 400,000 volts), or due to lack of generation to supply it with sufficient energy at each point in time, are exceedingly rare. The nominal standard of security of supply is for power cuts due to lack of generation to occur in 9 winters in a hundred.

The overall performance measure for electricity transmission is published on NGET’s website:[21] - this site includes a simple high level figure on transmission availability and reliability of supply – for 2008-9 this was 99.99979%. It is issues affecting the low voltage distribution systems, for which National Grid is not responsible, that cause almost all the 60 minutes or so per year, on average, of actual domestic power cuts. Most of these low voltage distribution interruptions are in turn, the fault of third parties such as workmen drilling through the street mains (or subterranean higher voltage) cables; this does not happen for transmission lines, which are mostly overhead on pylons. For comparison with supergrid availability, Ofgem, the electricity regulator, has published figures on the performance of 14 electricity distributors.[22][23]

Since 1990, there have only been two power cuts of high national promimence, that were linked to National Grid (although one was actually due to generation issues) :

The first case was in 2003, and related to the condition of National Grid's assets. National Grid was implicated in a power cut affecting 10 per cent of London in August - see 2003 London blackout. In essence, some news stories accused Grid of under-investment in new assets at the time; this was not necessarily true, but it did transpire that a transformer oil leak had been left untreated, except for top-ups, for many months, pending a proper fix. It also transpired that there was a significant error in a protection relay setting which became evident, resulting in a power cut, only when the first fault, the oil leak, had a real effect. National Grid took some time to admit to these aspects of the incident. It is arguable either way whether, with more money spent on system planning and maintenance, the human error in the relay setting could have been prevented.

The second case was in May 2008, and related to some generation issues for which National Grid was not responsible. A power cut took place in which a protective shutdown of parts of the network was undertaken by the distribution network operators, under pre-arranged rules, due to a sudden loss of generating capacity causing a severe drop in system frequency. What happened first, was that two of Britain's largest power stations, Longannet in Fife and Sizewell B in Suffolk, shut down unexpectedly ('tripped') within five minutes of one another. There was definitely no relationship between the two trips - the first did not cause the second. Such a loss is most unusual; Grid currently secures only against the loss of 1320 MW (the "infrequent infeed loss limit", due to rise to 1800 MW from 2014). There was, as a result, a sudden 1,510 megawatt adverse change in the balance of generation and demand on the supergrid. Because National Grid only secures against the near-instantaneous loss of 1320 MW, the frequency dropped to 49.2 Hz. Whilst the frequency was dropping to 49.2 Hz, or just after it reached that point, 40 MW of wind farms and more than 92 MW of other embedded (meaning, connected to the distribution system, rather than directly connected to the supergrid) generation, such as landfill plant, tripped on the basis of the rate of change of frequency ('ROCOF') being high, just as it is supposed to do under the G 59/2 connection rules.

The frequency stabilised at 49.2 Hz for a short while. This would have been an acceptable frequency excursion, even though it below the usual lower limit of 49.5 Hz, and recovery would not have been problematic. In fact, the fact that frequency stabilised at this level in spite of a beyond-design-basis event, could be viewed as reassuring. Ireland, which being a smaller system has a 'friskier' grid, sees about 10 frequency excursions below 49.5 Hz per year - her target frequency being 50 Hz, just as in Britain. Consumers would not have noticed the small drop in system frequency; other aspects of their supply such as voltage, remained perfect. There would, therefore, have been no consumer detriment; all would have been well at this point, had nothing further untoward occurred, and the incident was a credit to National Grid - although the incident was sure to be closely studied to see if lessons could be learnt.

Further issues, however, affecting smaller generators, arose. The problem was because the frequency had remained below 49.5 Hz for more than a few seconds, and because some generators' control settings were wrong. The current connection standard G 59/2 for embedded generation states that they must not trip (cease generating) as a result of sustained low frequency, until frequency has fallen below 47 Hz. However, a number of embedded generators are still using out of date control software that is not compliant with G59/2, as it erroneously trips them (as per the previous standard, G/59, in force when they were designed and specified) if frequency falls below 49.5 Hz for a few seconds. Because of the out of date software, another 279 MW of embedded generation tripped as a result of the low frequency whilst it was at 49.2 Hz. This was a problem as the Grid had no remaining available fast-acting generation, or demand-response, reserve margins. The frequency fell as a result to 48.792 Hz. The grid rules state that as frequency falls below 48.8 Hz, distribution network operators must enact compulsory demand control. This should start, if time permits, with voltage reduction, rapidly followed by the compulsory disconnection of, in stages, up to a final total of 60 per cent of all distribution-connected customers (a very small number of very large customers are connected directly to the supergrid; for them, other measures apply). There was no time to use voltage reduction (which keeps customers on supply, but subtly reduces their demand through reducing the voltage slightly); as a result, 546 MW of demand was automatically disconnected by distribution network operators. None of the directly supergrid-connected customers were cut off. National Grid had by now taken other measures to increase output at other generation sites (and demand had been reduced at those customer sites where the customer has volunteered for this to happen, in return for reimbursement, under demand-side response contracts with National Grid, or with their supplier). National Grid was able to restore system frequency. The average duration of loss of supply to the 546 MW of most low-voltage-connected (e.g. domestic) demand affected was 20 minutes. As to communications during the incident, National Grid did just have time to issue its most serious warning to all users of the supergrid, (demand control imminent, or DCI) before parts of the network were automatically disconnected by the operation of low frequency protection to ensure frequency was maintained within mandatory limits.[24][25][26]

See also


  1. ^ Mr Alan Shaw (29 September 2005). "Kelvin to Weir, and on to GB SYS 2005" (PDF). Royal Society of Edinburgh. 
  2. ^ "Survey of Belford 1995". North Northumberland Online. 
  3. ^ "Lighting by electricity". The National Trust. 
  4. ^ "the British Grid Code". 
  5. ^ National Grid
  6. ^ Energy Information Administration - International Electricity Installed Capacity Data
  7. ^ Electricity Stats
  8. ^ Time to Take a Fresh Look at CHP..., Simon Minett, Director, DELTA Energy and Environment, October 2005
  9. ^ Effect on Power Transfers, 2009 Seven Year Statement, National Grid
  10. ^ Table 7.5 - Effectiveness of Margihnal Generation due to Transmission Losses, 2009 Seven Year Statement, National Grid
  11. ^ a b "Appendix D Description of Balancing Services", Operating the Electricity Transmission Networks in 2020 - Initial Consultation, National Grid, June 2009,, retrieved 8 January 2011 
  12. ^ Gross, R; Heptonstall, P; Anderson, D; Green, T; Leach, M; & Skea, J (March 2006). The Costs and Impacts of Intermittency. UK Energy Research Centre. ISBN 1 90314 404 3. Retrieved 2008-07-15 
  13. ^ "Agenda 22 May 2007" (PDF). Archived from the original on 2010-11-03. Retrieved 2010-11-03. 
  14. ^ "NETA Despatch Instruction Guide" (PDF). Archived from the original on 2010-11-03. Retrieved 2010-11-03. 
  15. ^ "Wind Turbine Price List Uk". Archived from the original on 2010-11-03. Retrieved 2010-11-03. 
  16. ^ ^ What is the cost per kWh of bulk transmission / National Grid in the UK (note this excludes distribution costs
  17. ^ Commercial Opportunities for Back-Up Generation and Load Reduction via National Grid, the National Electricity Transmission System Operator (NETSO) for England, Scotland, Wales and Off-shore.
  18. ^ What is the cost per kWh of bulk transmission / National Grid in the UK (note this excludes distribution costs
  19. ^ Electric power transmission costs per kWh transmission / National Grid in the UK (note this excludes distribution costs)
  20. ^ Bernard Quigg, at a recent Claverton Energy Conference talking about transmission and distribution costs
  21. ^ "National Grid's total system availability". 
  22. ^ "First of two reports on low voltage British electricity system availability and other performance measures". 
  23. ^ "Second of two reports on low voltage British electricity system availability and other performance measures". 
  24. ^ Murad Ahmed, Steve Hawkes (2008-05-28). "Blackouts hit thousands as generators fail". The Times. 
  25. ^ Mark Milner, Graeme Wearden (2008-05-28). "Q&A: Blackout Britain". The Guardian. 
  26. ^ iPM. BBC Radio 4. 2008-05-31.

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