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UK Wind Constraint Payments Reach New and Exceptional Levels

Constraint payments to wind power are hitting new records on a regular basis. The highest daily total, £4.77m occurred on the 8th of October 2018, and the highest monthly total of £28.4m in September 2018, a staggering £5m more than the previous record of £23.2m in October 2017. The annual record, set last year, of £108m looks almost certain to be broken this year, where the total is already £101.5m to the 19th of October 2018.

Constraint payments to wind power, mostly but not now entirely in Scotland, comprise a staggering 8% of the cost recovered through the Balancing Services Use of System (BSUoS) charges, with a very substantial proportion of the remainder being caused by wind constraints that require conventional generation to be constrained on to the system south of the constraint to make up for the absence of contracted wind.

Some part of these records are the result of the late delivery of the 2,250 MW WesternLink High Voltage Direct Current (HVDC) link between Hunterston and Deeside, which was intended to enter service at the end of 2015, but has only just been commissioned in September 2018, due to a series of faults that must be both embarrassing for its builders, Siemens and Prysmian, and financially disappointing for its owners, National Grid and ScottishPower Transmission.

But the late arrival of this very expensive, more than £1bn, sticking plaster, probably adding upwards of £50m a year to consumer bills (it is a rule of thumb that grid imposes a standing charge on the consumer of about 5% of the capex for the 30 to 50 life of the asset), cannot explain all the increase observed, and certainly cannot provide a complete solution to what is clearly an acute and growing problem for the system.

What is going on? National Grid is being fairly cagey, and has not yet released comments on the vast constraints paid in September, but there is information coming out about the significant costs during the weekend of the 28th and 29th of July, when over £7m was paid out, with one large offshore wind farm in English and Welsh waters, alone, receiving about £1m over the period, according to the Balancing Mechanism data that REF publishes.

Presentations delivered at National Grid’s “Transmission Operation Forum” show that this was an event novel in character, consisting both of the by now familiar combination of high wind output and low demand (renewables are poorly correlated with demand patterns), and a series of unfortunate coincidences on the network. National Grid describes the event in the company’s obscure, acronym and jargon-laden Powerpointese thus:

There were several limitations on system operation for the ESO [Electricity System Operator], across both System and Energy. The flow of power North to South was restricted by a significant year ahead outage coupled with the HVDC [High Voltage Direct Current interconnector –the Western Link] not yet commissioned. In addition, a lack of conventional generation, displaced by high wind output, resulted in Negative Reserve, Voltage and ROCOF [Rates of Change of Frequency] problems. This resulted in actions on high priced wind units to solve Negative Reserve and Response requirements.

We can try to put this more clearly: the flow of energy from wind power in the North was restricted because some grid lines were out of action due to long-planned maintenance, a situation that was made worse by the fact that the WesternLink, which was expected to be in service by now, had experienced yet another fault. This basic difficulty was compounded by the fact that conventional generation, probably gas fired power stations, had been displaced from the market by wind power, leaving the grid network vulnerable to problems caused by voltage fluctuations, rapid changes in system frequency (which risks tripping embedded generators off the system causing cascading problems), and concerns that they would not be able to call on sufficient generation to reduce output and contain upward excursions in system frequency (negative reserve).

The high cost in dealing with this set of problems resulted from a novel development: the constraint boundary, normally located on the Anglo-Scottish border moved down to a location in the midlands, leaving several large offshore wind farms, including West of Duddon Sands, near Barrow-in-Furness, north of the constraint. Offshore wind farms charge more to reduce output than onshore wind farms ostensibly because they lose more subsidy per MWh lost when constrained off. As a matter of fact, and as shown in the REF blog in July, the charges ranged from £28 to £79 per MWh in excess of the subsidy lost.

National Grid illustrates the 28–29th July 2018 weekend problems with this map:

What do we learn from all this? As has long been predicted by systems analysts and grid engineers with practical experience of systems operation, the presence of large volumes of renewables on a system such as that of the UK will very significantly increase its fragility, making it vulnerable to unfortunate coincidences of adverse circumstances, such as those on the 28th and 29th July 2018. Addressing these problems is not, at least at present, impossible, but it is very expensive, and becoming more so.

We now await with great interest National Grid’s detailed explanations of the problems that required them to spend £28m of consumer funds on wind constraints in the month of September 2018 and the eye-watering £12.5m spent in just three days over 7–9th October 2018. Are these events exceptional, or just the New Normal?

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