National Grid (Great Britain)

In the electricity sector in the United Kingdom the National Grid is the high-voltage electric power transmission network serving Great Britain, connecting power stations and major substations and ensuring that electricity generated anywhere on it can be used to satisfy demand elsewhere. The network covers the great majority of Great Britain and several of the surrounding islands. It does not cover Ireland; Northern Ireland is part of a single electricity market with the Republic of Ireland.

This article is about the power grid in Great Britain. For the UK Ordnance Survey National Grid for mapping co-ordinates in Great Britain, see Ordnance Survey National Grid. For the company, see National Grid plc.
400 kV power line in Cheshire

The GB grid is connected as a wide area synchronous grid nominally running at 50 hertz. There are also undersea interconnections to other grids in northern France (HVDC Cross-Channel and HVDC IFA-2), Northern Ireland (HVDC Moyle), the Isle of Man (AC Isle of Man to England Interconnector), the Netherlands (HVDC BritNed) and the Republic of Ireland (HVDC EirGrid).

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 was already split into two separate entities, one for southern and central Scotland and the other for northern Scotland, with interconnectors. The first is owned and maintained by SP Energy Networks, a subsidiary of Scottish Power, and the other by SSE. However, National Grid plc continues to be the transmission system operator for the whole GB grid.[1]

History
Electricity pylons in an urban area in Pudsey, West Yorkshire.

At the end of the 19th century, Nikola Tesla established the principles of three-phase high-voltage electric 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,[2] and by 1912 had developed into the largest integrated power system in Europe.[3] 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.[4] 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.

National Grid helicopter inspecting overhead cables in Greater Manchester

The grid was created with 6,400 kilometres (4,000 mi) of cables – mostly overhead cables – linking the 122 most efficient power stations. The first "grid tower" was erected near Edinburgh on 14 July 1928,[5] and work was completed in September 1933, ahead of schedule and on budget.[6][7] It began operating in 1933 as a series of regional grids with auxiliary interconnections for emergency use. Following the unauthorised but successful short term parallelling of all regional grids by the night-time engineers on 29 October 1937,[8] by 1938 the grid was operating as a national system. The growth by then in the number of electricity users was the fastest in the world, rising from three quarters of a million in 1920 to nine million in 1938.[9] It proved its worth during the Blitz when South Wales provided power to replace lost output from Battersea and Fulham power stations.[9] 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.

At its inception in 1950, the 275 kV Transmission System was designed to form part of a national supply system with an anticipated total demand of 30,000 MW by 1970. The predicted demand was already exceeded by 1960. The rapid load growth led the Central Electricity Generating Board to carry out a study in 1960 of future transmission needs. The report was completed in September 1960, and its study is described in a paper presented to the Institution of Electrical Engineers by E.S. Booth, D. Clark, J.L. Egginton and J.S. Forrest in 1962.

Considered in the study, together with the increased demand, was the effect on the transmission system of the rapid advances in generator design resulting in projected power stations of 2,000–3,000 MW installed capacity. These new stations were mostly to be sited where advantage could be taken of a surplus of cheap low-grade fuel and adequate supplies of cooling water, but these situations did not coincide with the load centres. West Burton with 4 x 500 MW machines, sited at the Nottinghamshire coalfield near the River Trent, is a typical example. These developments shifted the emphasis on the transmission system, from interconnection to the primary function of bulk power transfers from the generation areas to the load centres, such as the anticipated transfer in 1970 of some 6,000 MW from The Midlands to the home counties.

Continued reinforcement and extension of the existing 275 kV systems was examined as a possible solution. However, in addition to the technical problem of very high fault levels, many more lines would have been required to obtain the estimated transfers at 275 kV. As this was not consistent with the Central Electricity Generating Board's policy of preservation of amenities a further solution was sought. Consideration was given to both a 400 kV and 500 kV scheme as the alternatives, either of which gave a sufficient margin for future expansion. The decision in favour of a 400 kV system was made for two main reasons. Firstly the majority of the 275 kV lines could be uprated to 400 kV, and secondly it was envisaged that the operation at 400 kV could commence in 1965 compared with 1968 for a 500 kV scheme. Design work was started and in order to meet the programme for 1965 it was necessary for the contract engineering for the first projects to run concurrently with the design. One of these projects was the West Burton 400 kV Indoor Substation, the first section of which was commissioned in June 1965. 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 super grid.

In the 2010 issue of the code that governs the British Grid, the Grid Code,[10] 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. British power system planners and operational staff therefore invariably speak of the Supergrid in this context.

In 2013 the construction of the 2.2 GW undersea Western HVDC Link from Scotland to North Wales started, which was completed in 2018.[11] This is the first major non-alternating current grid link within GB, though interconnectors to foreign grids already use HVDC.

Grid description
UK electricity production by source 1980–2018[12][13][14][15]
Electricity supplied (net) 1948 to 2008[16]
External image
Current grid status

The contiguous synchronous grid covers England (including the Isle of Wight), Scotland (including some of the Scottish islands such as Orkney, Skye[17] and the Western Isles which have limited connectivity[18]), Wales, and the Isle of Man.

Network size

The following figures are taken from the 2005 Seven Year Statement (SYS)[19]

  • 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)[20]
  • Number of large power stations connected to it: 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)

Total generating capacity is supplied roughly equally by renewable, nuclear, coal fired and gas fired power stations. Annual energy used in the UK is around 360 TWh (1.3 EJ), with an average load factor of 72% (i.e. 3.6×1011/(8,760 × 57×106).

Losses

Figures are again from the 2005 SYS.

  • Joule heating in cables: 857.8 MW
  • Fixed losses: 266 MW (consists of corona and iron loss; 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%.[21] 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%.[22]

Generated power entering the grid is metered at the high-voltage side of the generator transformer.[23][24] Any power losses in the generator transformer are therefore accounted to the generating company, not to the grid system. The power loss in the generator transformer does not contribute to the grid losses.

Power flow

In 2009–10 there was 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 was anticipated to grow to about 12 GW by 2014.[25] Completion of the Western HVDC Link in 2018 added capacity for a flow of 2.2 GW between Western Scotland and North Wales.[26]

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.[27]

Interconnectors

The UK grid is connected to adjacent European electrical grids by submarine power cables at an electricity interconnection level (transmission capacity relative to production capacity) which was 6% as of 2014.[28] The connections include direct-current cables to northern France (2 GW HVDC Cross-Channel and 1 GW HVDC IFA-2), the Netherlands (1 GW HVDC BritNed), Northern Ireland (500 MW HVDC Moyle), Republic of Ireland (500 MW HVDC East–West Interconnector) and Belgium (1 GW HVDC Nemo link). There is also the 40 MW AC cable to the Isle of Man (Isle of Man to England Interconnector). There are plans to lay cables to link the UK with Norway (1.4 GW NSN Link), Denmark via the 1.4 GW Viking Link, a third link with France,[29] and Iceland in the future.[30]

Grid storage

The UK grid has access to some large pumped storage systems, notably Dinorwig Power Station which can provide 1.7 GW for many hours.

There are also now some grid batteries, and as of June 2019 the UK's grid has 700MW of battery power attached with 70% annual growth.[31]

Reserve services and frequency response
Main article: National Grid Reserve Service

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 reserves act to keep the system's AC frequency within ±1% of 50 Hz, except in exceptional circumstances. These are used on a second by second basis to either lower the demand or to provide extra generation.[32]

Reserve services are a group of services each acting within different response times:[32]

  • Fast Reserve: rapid delivery (within two minutes) of increased generation or reduced demand, sustainable for a minimum of 15 minutes.
  • Fast Start: generation units that start from a standstill and deliver power within five minutes automatically, or within seven minutes of a manual instruction, with generation maintained for a minimum of four hours.
  • Demand Management: reduction in demand of at least 25 MW from large power users, for at least an hour.
  • Short Term Operating Reserve (STOR): generation of at least 3 MW, 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:[33]

  • The largest credible single generation failure event, 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 English and Welsh parts of the National Grid are controlled from the National Grid Control Centre which is located in St Catherine's Lodge, Sindlesham, Wokingham in Berkshire.[34][35][36][37] It is sometimes described as being a 'secret' location.[38] As of 2015 the system is under consistent cyber attack.[39]

Although the transmission network in Scotland is owned by separate companies – SP Transmission plc (part of Scottish Power) in the south, and Scottish Hydro Electric Transmission plc (part of Scottish and Southern Electricity Networks) in the north[40] – overall control rests with National Grid Electricity System Operator.[1]

Transmission costs

The costs of operating the National Grid System are recouped by National Grid Electricity System Operator (NGESO) through levying of Transmission Network Use of System (TNUoS) charges on the users of the system.[41] The costs are split between the generators and the users of electricity.[42]

Tariffs are set annually by NGET, and are zonal in nature—that is, the country is divided into 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 a metric of demand, which reports retrospectively three numbers about peak demand between November and February (inclusive) each winter. In order to encourage usage of the National Grid to be less 'peaky', the triad is used as the basis for extra charges paid by the users (the licensed electricity suppliers) to the National Grid: the users pay less if they can manage their usage so as to be less peaky.

For each year's calculation, historic system demand metrics are analysed to determine three half-hour periods of high average demand; the three periods are known as triads. The periods are (a) the period of peak system demand, and (b) two other periods of highest demand which are separated from peak system demand and from each other by at least ten days.

For power stations, the chargeable demand is only the net site demand (per CUSC rule 14.17.10), so when the site is net exporting (i.e. total metered generation at that site exceeds total separately-metered station demand), that separately-metered station demand shall not be liable for demand TNUoS charges in relation to the station demand at triad.

Triad dates in recent years were:

YearTriad 1Triad 2Triad 3
2015/16 [43]Wednesday 25 November 2015, 17:00 – 17:30Tuesday 19 January 2016, 17:00–17:30Monday 15 February 2016, 18:00–18:30
2016/17 [44]Monday 5 December 2016, 17:00 – 17:30Thursday 5 January 2017, 17:00 – 17:30Monday 23 January 2017, 17:00 – 17:30
2017/18 [45]Monday 11 December 2017, 17:30 – 18:00Monday 26 February 2018, 18:30–19:00Monday 5 February 2018, 18:00–18:30

In April of each year, each licensed electricity supplier (such as Centrica, BGB, etc.) is charged a yearly fee for the 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. The average for the whole country is about £15,000/MW. This is a means for National Grid to recover its 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 for high-voltage long-distance transmission (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.

Triad charges encourage users to cut load at peak periods; this is often achieved by using diesel generators. Such generators are also routinely used by National Grid.[46]

Estimating costs per kW⋅h 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).[42]), then a crude estimate can be made of transmission costs, and one gets the figure of around 0.2p/kW⋅h. Other estimates also give a figure of 0.2p/kW⋅h.[42]

However, Bernard Quigg notes: "According to the 06/07 annual accounts for NGC UK transmission, NGC carried 350TW⋅h 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 kW⋅h.",[47] 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 BEIS) 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 average demand during the triad periods multiplied by the tariff for their zone. Therefore, (as of 2007) a customer in London with a 1 MW average 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.

Constraint payments

Constraint payments are payments to generators above a certain size, where the National Grid gives them dispatch instructions that they are unable to take the electricity that the generators would normally provide. This can be due to a lack of transmission capacity, a shortfall in demand, or unexpected excess generation. A constraint payment is recompense for the reduction in generation.[48]

Major incidents

Power cuts due to either problems on the infrastructure of the supergrid (defined in the Grid Code as the transmission system operated by National Grid, which in England and Wales comprises lines energized 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 nine winters in a hundred.

The overall performance measure for electricity transmission is published on NGET's website[49] and includes a simple high-level figure on transmission availability and reliability of supply. For 2008–9 this was 99.99979%. Issues affecting the low voltage distribution systems – for which National Grid is not responsible – cause almost all the 60 minutes or so per year, on average, of 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 to major transmission lines, which are for the most part overhead on pylons. For comparison with supergrid availability, Ofgem, the electricity regulator, has published figures on the performance of 14 electricity distributors.[50][51]

Since 1990, there have been three power cuts of high national prominence that were linked to National Grid, two due to generation issues.

August 2003

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 percent of London in August – see 2003 London blackout. Some news reports accused Grid of under-investment in new assets at the time; it transpired 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.

May 2008

The second case was in May 2008, and related to 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. First, 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 no relationship between the two trips: the first did not cause the second. Such a loss is most unusual; at that time, Grid secured only against the loss of 1320 MW – the "infrequent infeed loss limit" (which rose to 1800 MW from 2014). The two shutdowns caused a sudden 1,510 MW adverse change in the balance of generation and demand on the supergrid, and 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 generation (meaning, connected to the distribution system, rather than directly connected to the supergrid), 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 was below the usual lower limit of 49.5 Hz, and recovery would not have been problematic. 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 more temperamental (and therefore less stable) grid, sees about 10 frequency excursions below 49.5 Hz per year – Its 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.

However, further issues affecting smaller generators arose because the frequency remained below 49.5 Hz for more than a few seconds, and because some generators' control settings were wrong. The 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 used 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. For this reason, 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.

Grid rules state that as frequency falls below 48.8 Hz, distribution network operators must apply 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 percent 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 then able to restore system frequency. The average duration of loss of supply to the 546 MW of mostly low-voltage-connected (e.g. domestic) demand affected was 20 minutes.

National Grid had time to issue a warning to all users of the supergrid – "demand control imminent" – which is one step away from its most serious warning "demand disconnection warning". During these incidents, the system was at risk to further generation loss which could have resulted in parts of the network being automatically disconnected by the operation of low frequency protection to ensure frequency is maintained within mandatory limits.[52][53][54]

August 2019

The third event occurred on 9 August 2019, when around a million customers across Great Britain found themselves without power.[55] Lightning struck a transmission line at 4:52 pm, causing the loss of 500 MW embedded (mostly solar) generation. Almost immediately, Little Barford Power Station and Hornsea Wind Farm tripped within seconds of each other, removing 1.378 GW of generation which was in excess of the 1 GW of backup power the operator maintains.[56] The grid frequency fell to 48.8 Hz before automatic load-shedding disconnected 5% of the local distribution networks (1.1 million customers for 15 to 20 minutes); this action stabilised the remaining 95% of the system and prevented a larger blackout.[57] Although power was maintained at all times to the railway network (but not to the signalling system), the reduction in frequency caused 60 Thameslink Class 700 and 717 trains to fail. Half were restarted by the drivers but the others required a technician to come out to the train to restart it.[56] This led to substantial travel disruption for several hours on the East Coast Main Line and Thameslink services. The supply to Newcastle Airport was also disrupted and a weakness was exposed in backup power arrangements at Ipswich Hospital.[56]

An investigation by Ofgem concluded in January 2020. It found that Little Barford and Hornsea One had failed to remain connected to the grid following the lightning strike, and their operators – RWE and Ørsted respectively – agreed to each pay £4.5 million to Ofgem's redress fund. Additionally, Ofgem fined distribution network operator UK Power Networks £1.5M for beginning to reconnect customers before being cleared to do so, although this breach of procedure did not affect the recovery of the system.[58][59]

Minor incidents

November 2015

On 4 November 2015 National Grid issued an emergency notice asking for voluntary power cuts because of "multiple plant breakdowns". No power cuts occurred but wholesale electricity prices rose dramatically, with the grid paying up to £2,500 per megawatt-hour.[60]

See also

References
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Further reading
  • Hannah, Leslie (1979). Electricity Before Nationalisation, A Study in the Development of the Electricity Supply Industry in Britain to 1948. London & Basingstoke: Macmillan Publishers for the Electricity Council. ISBN 0-8018-2145-2.

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