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REF Blog

Paying Wind Farms to Stop Generating in 2018

Constraint payments to wind farms, that is payments to stop generation, mostly in Scotland, reached record levels in 2018, with the total reaching £124,649,106, as compared to the total in 2017, of £108,247,860.

Of this, £115,716,335 was paid to Scottish wind farms, and nearly all of that, £115,313,091 went to onshore wind farms. These costs are, of course, passed through to consumers in their bills.

The new record data generated a number of stories in the press including the Sunday Times, the Times and the Scottish Daily Mail.

Of particular interest is that behind this record lies the fact that many wind farms received constraint payments for the first time in 2017 and 2018, as shown in the map below, including some such as Stronelairg that began to be constrained off (28 December 2018) within weeks of being connected to the system.

Windfarms First Constrained 2017 2018

Figure 1: Newly constrained wind farms in 2017 (Green dots) and 2018 (Red dots)

There is a growing suspicion that the probability of major constraints is a factor in site selection, since it increases the average earnings per MWh generated as a result of the scale of compensatory constraint payments allowed, which are, and we think unjustifiably, well above lost income. Constraints can account for a substantial part of the potential output of a wind farm.

It is possible from market data to produce reasoned estimates of the fraction of output that is discarded. The following table lists the wind farms with the highest proportion of constrained off energy, which ranges from just below 30% to around 15%. These are high fractions, and, given that constraint payment compensation, which averages £70/MWh, is over 50% in excess of the lost income (£45/MWh) make a material difference to the annual income of the site.

These matters are not at present adequately addressed in the planning system, but clearly should be. Decisions makers should be aware that a site may have been chosen precisely because it lies behind a constraint, and in spite of other material considerations, such as local environmental impacts.

Table 1. Estimated proportion of total generation in 2018 that received payments through the Balancing Mechanism not to be generated. For example, Bhlaraidh generated approximately 192 GWh in 2018 and a further 80 GWh was constrained resulting in the 29% figure in Table 1.

Onshore Wind Farm First Constraint Date % Constrained 2018
Bhlaraidh 10/08/2017 29%
Strathy North 23/07/2015 25%
Dunmaglass 23/09/2016 24%
Fallago 29/04/2013 24%
Black Law I 30/05/2010 24%
Dersalloch 21/11/2016 21%
Hadyard Hill 01/04/2011 21%
Arecleoch 10/09/2011 20%
Griffin 09/11/2012 20%
Harestanes 11/08/2014 19%
Whitelee 30/05/2010 19%
Beinn Tharsuinn 05/10/2010 19%
Farr 05/04/2011 19%
Ewe Hill II 16/05/2017 18%
Black Law II 09/09/2016 17%
Kilbraur 16/05/2011 16%
Gordonbush 06/06/2012 16%
Hare Hill 28/06/2017 15%
Clyde 09/11/2012 15%
Beinn an Tuirc 30/06/2013 15%


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High Wind Farm Constraints Continue in Spite of WesternLink Interconnector

The long overdue commissioning of the WesternLink Anglo-Scottish subsea interconnector, completed earlier this month, appears to be mitigating the need to constrain off Scottish wind power, but the delay in the cable’s delivery has meant that it has been overtaken by overall growth in wind on the network, and constraint payments continue, with over £2m being paid out to forty wind farms yesterday, the 23rd of October 2018, with an average price of £69/MWh, well above the lost income of £45/MWh.

Nevertheless, the WesternLink does appear to be facilitating very high, record-breaking levels of wind on GB’s electricity system. For example about 11 GW of wind was carried over a single settlement period (SP 41 which covers the period 8:00- 8:30 PM) on the 23rd of October 2018. This can be seen clearly in the two figures below, generated from REF’s free, online fuel mix database, which is based on Nationall Grid data.  The first panel shows the total fuel mix, and the second panel the renewables and interconnectors alone.

Oct23 Fuel Mix

Nevertheless, in spite of the high levels of wind actually facilitated, constraint payments are still very significant, particularly between midnight and 8am, when demand is low. For instance, in Settlement Period 1 on the 23rd, just after midnight, GB transmission system demand stood at 22 GW, while total wind was approximately 10.8 GW, of which 8.4 GW was actually used, with some 2.4 GW constrained off at a cost of £86,000 for that half hour period. Without constraints there would have been about 50% wind on the system.

It is interesting to note that the interconnectors to France and Holland were acting as import channels at this time, with a total of 1,660 MW, a reminder that the system and its markets are not, and probably never can be, made infinitely flexible in the interest of accommodating wind.

National Grid had earlier predicted a Balancing Services Use of System (BSUoS) cost of £2.11/MWh for the 23 October 2018, and it will be interesting to see if these forecasts, which reflect expectations for the WesternLink, are accurate.

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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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Record UK Wind Farm Constraint Payments of £28m for September 2018

September 2018 has seen the highest monthly payments to wind farms to stop generating since records began in 2010.

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Weekend constraint payments record

Constraint payments to wind farms in the United Kingdom totalled £7.12m over the weekend, 28–29 July 2018, making it the most expensive weekend to date and well above the previous record of £5.87m for 24-25 June 2017. Constraints on Saturday the 28th of July amounted to £4.41m, and on Sunday the 29th to £2.71m.

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Interconnector problems mean wind farm constraint payments continue

Over the last few days REF has been delving into the wind constraint payments data to assist an investigation by the Scotsman newspaper into ongoing problems with the Western Link HVDC Interconnector, a 2.2 GW, £1 billion subsea cable from Hunterston to Deeside expressly built to carry Scottish renewable electricity to English and Welsh consumers.

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Early Rooftop Solar PV Adopters Get Lion’s Share of the FiT Subsidy

As is well known, the generous subsidies given initially to small scale solar PV under the UK Feed-in Tariff resulted in unexpectedly high levels of adoption. Government quickly reduced subsidies for new installations, but did not feel able to retrospectively cut the arguably excessive support for early adopters. Consequently, even today, in 2017, nearly one quarter of the total annual cost of the scheme is being paid to the small-scale rooftop panels erected in the first two years of the scheme, 2010–2012.

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The Total Cost of Subsidies to Renewable Electricity in the United Kingdom: 2002–2016

REF is often asked about the total cost of public support to renewable electricity generators, both annually and since the subsidies began.

The following table gives aggregate figures for the administrative years 2002–2003 to 2015–2016. Administrative years run from the 1 April to 31 March the following year.

Year RO (£m) FiT (£m) Total (£m)
2002-2003 278 278
2003-2004 416 416
2004-2005 495 495
2005-2006 583 583
2006-2007 719 719
2007-2008 876 876
2008-2009 1,036 1,036
2009-2010 1,119 1,119
2010-2011 1,285 14 1,300
2011-2012 1,458 151 1,608
2012-2013 1,991 506 2,498
2013-2014 2,599 691 3,290
2014-2015 3,114 866 3,980
2015-2016 3,743 1,110 4,853
Total (£m) 19,818 3,338 23,156
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Santa's Christmas present for wind farms

Over the Christmas period, high winds accompanying Storms Barbara and Conor combined with low demand for electricity to deliver a £7 million gift to the owners of wind farms in the form of constraint payments. Constraint payments occur when wind farms are paid not to generate, usually in periods when wind generation is surplus to demand. The bulk of these payments are made when wind generation cannot be used in Scotland, and there is insufficient grid capacity to export the energy to England. The cost of these payments is borne by electricity bill payers throughout the United Kingdom.

The peak payments over the current holiday season were made on Christmas Day, as summarised in the following table drawn from the REF datasets:

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Renewables planning activity in the last six months

As regular users of the REF datasets will know, our EU Target Tracker is updated monthly and based on the government’s Renewable Energy Planning Database (REPD). This month’s update has just been released, and merits a general comment.

As a rule, the totals change little month on month, with the major trends only being visible over longer timescales. Focus on the short term and net changes is a mistake. It is only by studying the changes at the individual planning application level over 6 months or longer that we can see the major trends and the impacts of changes in government policy.

To that end, we have compared the detailed planning data released for April 2016 with that released this week for November 2016. We looked at how many new applications have been submitted in the last half year, how many abandoned, how many were granted or refused planning permission, how many appealed by the developers, and how many have begun construction and operation. Predictably, 80-90% of the activity involves onshore wind, solar photovoltaic and offshore wind.

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