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Constraint Payments to Hornsea Offshore Wind

Introduction: Inertia and Frequency
There is much talk about the importance of "energy storage" to enable the adoption of renewables. It is often forgotten in such discussions that the conventional electricity system, of fossil fuelled and nuclear power stations, already has a large storage component built into it. This energy store is found in the rotating mass of the turbine shafts in the generators, and also, to a lesser extent, in the rotating mass of the large electric motors used by some electricity consumers. The rate at which the shafts of those generators, and synchronised motors, are turning is determined by the chosen electricity System Frequency, which in the UK is 50 Hz, or 50 revolutions a second, 3,000 rpm. In almost exactly the same way that a gyroscope has stability and resists attempts to move it due to the energy stored as kinetic energy in its rapidly turning wheel, the synchronised rotations of the electricity generators deliver system "inertia" making it robust against accidents and other surprises, for example an unforecast increase in electricity demand, a grid line failure or the loss of one or more power stations. The energy stored in the spinning mass of the turbines can be drawn down very briefly to buffer the shock and allow time for other generators to increase their output to address the shortfall. In that event, the frequency of the system falls as all the generators slow down due to loss of energy.

Unfortunately, not all generators are capable of operating in this synchronised fashion, and these generators do not contribute to inertia. Solar photovoltaics, for example, have no rotating parts, and wind turbines do not have sufficient mass in their generator shafts to contribute significantly to inertia. Consequently, these generators operate asynchronously, as do the electricity interconnectors with the networks of other countries.

As the proportion of renewable generation and the increased reliance on interconnectors has grown in the UK, the average inertia of the system at any moment has declined, meaning that the system would be less resilient in the face of an accident unless compensating measures were taken, for example the addition of asynchronous compensators (effectively flywheels), generation capable of a very rapid response, such as pumped storage hydropower, or other energy storage devices such as batteries.

It has been assumed hitherto that the UK System Operator, National Grid ESO, was taking adequate steps to ensure that declining inertia was not a threat. However, the load shedding causing local blackouts over the United Kingdom on the afternoon of the 9th of August this year, has put National Grid's management of the system under the spotlight, raising many questions.

The Blackouts on the 9th of August

National Grid has a target frequency of 50 Hz at all times, and is legally required under the terms of its operating licence to maintain frequency between the narrow limits 49.5 Hz and 50.5 Hz. In fact, National Grid's "normal operating limits" are even more stringent at 49.8 Hz to 50.2 Hz. If frequency falls below 48.8 Hz, National Grid will automatically start to disconnect consumers to reduce the demand for energy and try to bring the energy input back into line with energy demand so that frequency can rise to normal levels.

Stable frequency is important for consumers, but it is also critical for synchronised generators. If system frequency falls, this implies that more energy is being taken out than is being generated by power stations. When this happens, those stations that are still connected come under intense mechanical strain, which they cannot tolerate for long. Demand and supply could be thought of as two teams engaged in a tug-of-war. If one of the team members on the supply side suddenly lets go, the strain on the other supply team members increases, perhaps causing injury. The situation facing generators is not dissimilar. In order to protect themselves from major mechanical damage, stations have to disconnect, even though this will almost certainly further reduce the frequency, thus making the system's overall problem even worse. (Generators also have to disconnect if system frequency rises, in other words the turbine shafts start spinning more quickly, because more energy is being put into the grid than is being taken out, though upward frequency excursions, as they care called, are considerably less common.)

The grid event on the 9th of August was a case of an accident in a fragile system leading to power station disconnections ("trips" as they called), and a large fall in frequency placing other power stations under strain, leading to further trips, and then to consumer blackouts to reduce electricity consumption.
National Grid's own interim report shows that the proximal cause of the event was a lightning strike somewhere in Cambridgeshire. This caused some 500 MW of embedded generation to trip. This embedded generation probably included a mixture of wind, solar, and smaller scale fossil-fuelled generators. Just afterwards, or perhaps simultaneously (the interim report is not clear on this point), the Hornsea offshore wind farm reduced its output from 800 MW to 62 MW in a fraction of a second (165 milliseconds to be precise). Shortly after that, the steam turbine at the Little Barford Combined Cycle Gas Turbine power station also tripped. Without the steam turbine it was inevitable that the gas turbines would also have to trip, and this did occur about a minute later.

It is not known why the embedded generators or Hornsea offshore wind were sensitive to the lightning strike. Power systems engineers, have suggested to REF that there may be a feature of the transmission grid in the affected geographical area that makes the frequency protection systems in generators more likely to return a false positive, in other words to trip when they need not have done so. This is as yet uncertain.

Constraint Payments to Hornsea after the Blackout: Saturday–Sunday 10th–11th

Late on Saturday night, the day after the blackout, and for the following 11 hours, National Grid paid Hornsea to reduce output for the first time. This payment was explicitly designated in the market data as resulting from a Constraint, and it appears in our Constraints Payments database.

The volume of energy constrained off was just over 500 MWh for which Hornsea was paid over £98,000. The price charged by Hornsea varied between £164/MWh, and £201/MWh over the period. This variation in price over a short time period is in itself unusual, and deserves investigation by Ofgem, since it seems to suggest that Hornsea was exploiting its position behind a constraint for profit, contrary to the Transmission Constraint Licence Condition. In any case, the price is well in excess of the current market value of Hornsea's Contract for Difference (£158.75). As one of the newer offshore wind farms, its CfD strike price is one of the lowest for offshore wind farms. Consequently, it is surprising that the prices charged in the Balancing Mechanism for reducing output is the highest of all offshore wind farms constrained off this year.

It is not clear why Hornsea was constrained off over this period, but we note that the frequency drifted both above and below National Grid's normal operating limits with a peak at 50.252 Hz and a trough at 49.774 Hz 8 mins 15 secs later, shortly before the constraints to Hornsea began (see Fig 1 below). It is not clear whether the frequency variations, and particularly the excursion below the normal operating limit of 49.8 Hz, is related to the constraint payments made to Hornsea, but so soon after the involvement of this wind farm in a major system failure there is clearly some ground for suspecting that it might be so. The Department of Business, Energy and Industrial Strategy (BEIS) has initiated its own inquiry, alongside those of the regulator, Ofgem, and National Grid. It is to be hoped that these inquiries may shed further light on this question.

Figure 1: The electricity grid frequency at 15 second intervals on the evening of 10 August 2019

Table 1: Constraint payments for Hornsea offshore wind farm on the 10-11 August 2019 for each half hour settlement period where settlement period 48 is for 23:30-00:00 BST or 22:30-23:00 GMT.

Date Settlement Period Total Cost (£) Volume of energy constrained (MWh) Price (£/MWh)
2019-08-10 48 £3,249 17.56 £185
2019-08-11 1 £4,671 24.50 £191
2019-08-11 2 £4,671 24.50 £191
2019-08-11 3 £4,812 24.50 £196
2019-08-11 4 £4,812 24.50 £196
2019-08-11 5 £4,918 24.50 £201
2019-08-11 6 £4,918 24.50 £201
2019-08-11 7 £4,906 24.50 £200
2019-08-11 8 £4,906 24.50 £200
2019-08-11 9 £4,893 24.50 £200
2019-08-11 10 £5,709 28.58 £200
2019-08-11 11 £5,864 29.50 £199
2019-08-11 12 £5,913 29.75 £199
2019-08-11 13 £5,764 30.00 £192
2019-08-11 14 £5,475 28.50 £192
2019-08-11 15 £964 5.33 £181
2019-08-11 16 £2,801 15.50 £181
2019-08-11 17 £3,399 20.00 £170
2019-08-11 18 £3,399 20.00 £170
2019-08-11 19 £3,210 19.17 £167
2019-08-11 20 £2,708 16.17 £167
2019-08-11 21 £3,290 20.00 £164
2019-08-11 22 £2,906 17.67 £164

At the same time that it was paying Hornsea to reduce output, National Grid was instructing conventional CCGT plant in the region both to increase output and to start generating. These generators included those at Staythorpe, Keadby, South Humber Bank, which all started generating, and Salt End, and Cottam which were instructed to increase output. Thus, instructing Hornsea to reduce output does not appear to be an action intended to address a simple excess of generation in the area but suggests that National Grid may have been concerned at low inertia, and was seeking to increase inertia relative to load by reducing asynchronous generation (Hornsea offshore wind) and simultaneously increasing synchronous generation (CCGT).

We note that National Grid continued to constrain Hornsea Offshore wind on the 15th, 17th, 18th, and 19th of August, curtailing output of 522 MWh, and paying Hornsea just over £100,000 to do so. Prices per MWh remain high, and continue to vary widely, from a minimum of £179/MWh to a maximum of £202/MWh. At the time of writing, 27th August, there have been no further constraints since the 19th of August.

Conclusions

1. Low system inertia is a growing concern in the UK, and there is some ground for thinking that it was at least a contributory factor to the severity of the blackout on the 9th of August. The constraint payments to Hornsea Offshore wind, along with those to CCGT to increase output, are consistent with this hypothesis, and deserve investigation by government and the regulator.
2. We note, that there may also be location specific problems with the network in this area, making the frequency protection systems liable to false positives in the event of a fault such as a lightning strike.
3. In any case, the high and varying prices charged by Hornsea Offshore Wind to reduce output are suggestive of an abuse of market power, and appears to be a contravention of the Transmission Constraint Licence Condition. Ofgem should investigate to determine whether this interpretation is correct, and if it is should intervene to prevent this behaviour and ensure it does not spread into the wider market.

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