Renewable Energy Foundation

In 2022, REF highlighted the fact that so-called ‘unsubsidised’ wind farms were charging to reduce generation during periods of grid constraint (“Why are ‘Unsubsidised’ Wind Farms Receiving Constraint Payments?”)

We could see no justification for wind farms that are not losing income when constrained to charge for any reduction in output. Their commercial position is not harmed, and therefore the constraint payment represents additional and unearned income.

The regulator, Ofgem, has the authority to prevent such overcharging under the terms of the Transmission Constraint Licence Condition (TCLC) and we raised this matter directly with Ofgem in October 2023 and again in May 2024 but have received no substantive reply.

Table 1 shows the wind farms which are or have been unsubsidised while taking constraint payments. Included are Moray East and Hornsea 1 & 2 offshore wind farms which deferred implementing their Contracts for Difference subsidy, in the case of Moray East by two and a half years. The total payments to this category of wind farm exceed £340 million, which we consider to be vastly in excess of what could be argued was justifiable.
Our conclusion has received further support in recent weeks from the fact that the bid price for reducing output for some of these wind farms has fallen sharply.

It is not apparent whether this fall in prices is because of a belated intervention from Ofgem or whether the wind farms themselves have at last recognised that the Transmission Constraint Licence Condition precludes profiting from grid constraints.

Table 1: List of ‘unsubsidised’ wind farms taking constraint payments 

REF is today (23 January 2025) publishing a study by Professor Gordon Hughes which reveals that the increasing share of intermittent and subsidised renewable generation has increased electricity price variability. Consequently, there are potential cost benefits to using smart meters to shift to dynamic and peak/off-peak consumer tariffs instead of the current standard of fixed electricity prices.

The study also explores the ideas that the impacts of intermittent and subsidised renewable energy on consumer prices could be mitigated by increased storage or imports from other countries and demonstrates that on current evidence neither is likely to provide realistic solutions.

The study also shows that the current trend, as exemplified by Contracts for Difference (CfDs), is towards a fully “pooled” or average pricing system. This will further increase already very high costs to consumers.

Professor Hughes remarks:

“In as far as any general policy goal can be discerned, this seems to be a consistent desire to hide – and socialise or pool – the costs of promoting low carbon forms of generation.” (p. 7).

We conclude from Professor Hughes’ study that the consumer interest would be best served by a firm shift towards a variable pricing mechanism, for which there have always been good reasons. But this would require two governmental actions:

1. Smart meters are essential to a variable pricing system, but the UK deployment of such meters has been deeply unsatisfactory, and compares very unfavourably with that in other countries. The government would need to address this as a matter of urgency.

2. Variable pricing will require government to be entirely candid about the underlying costs of the Net Zero targets, which are as a matter of demonstrable fact extremely high.

Highlights of the report:

ELECTRICITY PRICE VARIABILITY
• The increase in intermittent wind and solar renewable energy in the GB energy system has caused a significant increase in the volatility of electricity market prices (page 12)
• This is expected to continue for at least 5 to 10 years as more intermittent generation is built. (page 24)
• Increased volatility of market prices causes increases in the cost of hedging (insuring) which is passed on to the consumer (page vi)
• Market prices are predicted to be negative for nearly 10% of hours by 2030 (page 25)

ELECTRICITY STORAGE SOLUTIONS
• Increasing electricity storage via pumped hydro or large-scale batteries is often suggested as a means of dealing with increased variability in generation but calculations described in the report show that the average storage margins in 2023 are less than 40% of what is required to cover the cost of capital for such projects indicating neither can proceed without subsidy. (page 17-19)

IMPORTS
• Evidence on imports via interconnectors is given to show that higher UK electricity prices do not increase imports, but instead are associated with lower imports from continental Europe (page 20-21).

TRANSPARENCY
• Modest changes in consumption patterns can mitigate some of the combined impact of intermittent renewable generation and within-day variations in electricity demand. (page 21)
• This would require more transparency and education than has hitherto been promoted by Government, electricity suppliers or Ofgem. For example, electricity bill payers need to be aware they are not primarily paying for electricity. Instead, they are paying for the complex grid and system infrastructure associated with meeting high variable demand plus a set of levies to pay for the Government’s very expensive net zero aspirations. (page 23)
• The reality is that the share of retail electricity bills due to the wholesale cost of electricity has fallen to about 20%. (page 14)

CHANGES IN CONSUMER TARIFFS
• Different retail tariff options are already commonplace in other European countries where consumers are offered flexible tariffs with different prices depending on the time of day, or a dynamic tariff linked directly to market prices with a fixed charge for all other costs. (page 13-17)
• The potential for consumer savings is indicated by the difference between the average retail price in mid-2024 of 29.5p per kWh compared with the spot price of 6.3p per kWh. (page 23).
• The suggested improved tariff regime is dependent on the availability of smart meters. The report notes that the rollout of smart meters in other countries has been faster and at a lower cost. (page 1)

Wind farm constraints continue to rise, both in total volume and in cost. In 2024 the consumer paid more than £393 million in direct costs - and very much more than this in indirect costs – to discard 8.3 TWh of wind energy.

By comparison, in 2023, 4.3 TWh of wind-generated electricity was discarded at a direct cost of £310 million.

The prices being charged by wind farms to reduce output fell in 2024 in spite of subsidies having risen, which supports our view that prices have hitherto been excessive.

However, planning application data shows that the, in our view, indefensibly high rewards for constraints continue to incentivise wind farm development in areas of the UK that have low demand and weak grid connection, resulting in high constraints.

The bulk of the additional volume and cost of constraints is due to the ever-increasing number of Scottish wind farms being sited remote from areas of demand: more than 98% of the total constrained volume arises from Scottish wind farms.

In particular, the offshore wind farm, Seagreen, whose majority owner is SSE, was alone responsible for 40% of the total volume of constraints. Seagreen is currently unsubsidised but 25% of its capacity has been awarded an as yet unimplemented Contract for Difference (CfD).

Figure 1: Top twenty wind farms with highest constrained wind output in 2024

In another blog post we have explained how deferring take-up of a CfD has enabled heavily constrained wind farms to make very significant earnings over and above what they might have made under the CfD regime.

Seagreen is clearly woefully located from the perspective of the consumer, and excellently placed for SSE and the other shareholders. Because so much of its potential output could not be used, its load factor was a mere 14% in 2024. To put this in context, government expects offshore load factors to be in the region of 40%. However, this extremely low productivity does not translate into lower earnings for the wind farm. On the contrary, it actually earns more than it would by selling to the market. This paradoxical outcome arises because Seagreen gets paid as if it had actually generated and sold the electricity, and on top of that charges an extra premium per MWh for reducing output. Bad though this is for the consumer, further insult is added to the injury because the System Operator must now bring the market back into physical balance by purchasing electricity equivalent to the constrained volume from a generator south of the grid constraint.

Putting aside the additional costs south of the constraint, the scale of the consumer cost of Seagreen can be estimated thus: in 2024 the consumer paid Seagreen £104 million for actually generating electricity, plus £198 million for the constrained volumes, and £64 million for the premium charged to reduce output.

This gives a total of £367 million.

The amount of green electricity actually generated by Seagreen in 2024 was 1.36 TWh. Therefore the cost to the consumer of Seagreen’s actually generated wind power was £270 per MWh.

To provide context for this cost, the current strike price sought by Seagreen in its Contract for Difference is £55 per MWh. No wonder that companies are reluctant to implement their contracts.

The industry and Ofgem are aware that the way that wind farm constraints are managed is not in the consumer interest. In November 2023 the then National Grid Electricity System Operator (now nationalised as National Electricity System Operator) proposed a change to the electricity market to mitigate some of these costs. The proposal document noted that the true cost to consumers of wind farm constraints was not transparent, that the market was not efficient, and that competition between generators was not fair and that consumers were paying over the odds.

They assessed that the worst-case scenario of doing nothing about the situation could result in up to £16 billion in consumer costs being incurred by 2030, a very large burden on an already heavily pressured consumer. The deadline initially set for the NESO recommendation was September 2024. However, this deadline has now been put back to April 2026. Given the scale of the annual costs this lack of urgency is deplorable, and we can only assume that neither the industry nor the government is seriously committed to addressing unfair consumer costs.

Introduction and Summary

Those who have followed the history of the Contracts for Difference (CfD) scheme for subsidising renewables will be aware that some wind farms deliberately deferred implementing their contract with the British consumer in order to profit from a spike in market prices. Even the Department of Energy Security and Net Zero (DESNZ) admitted to the press that this was “not in the spirit of the scheme”. DESNZ attempted to deal with this sharp practice by tightening the contracts.

But experienced commercial players are extremely resourceful and appear to have found another way to secure a similar end by building and connecting well ahead of the specified start date for the contract.

For example, the Viking Wind Farm on the island of Shetland has two CfDs, one under Allocation Round 4 for half of its 443 MW, and one for the remaining half under round 5. These contracts are set to start in 2027 and 2028 respectively. But the construction of Viking and its interconnector were completed earlier this year, and it started operation in June this year, taking the market price for what energy it generated and also enjoying extremely generous constraint payments, discarding about 62.5% of its potential output while still receiving market prices for the constrained-off volume as well.

We estimate that Viking has earned over £10m in this month alone, when it would have only received about £3.5m if it had been paid under the CfD and had not been constrained. This implies a staggering price of about £199/MWh, as opposed to the already generous CfD price of £67/MWh.

These facts make a mockery of claims that projects such as Viking offer good value to consumers, or, as Viking’s launch publicity claimed, that this would one of the most productive onshore wind farms in Britain. On the contrary, it is shaping up to be one of the most heavily constrained, least productive and yet extortionately profitable wind projects ever built.

Summary:

A recent study by Bloomberg has drawn attention to the way that wind farms overstate likely generation at times of constraint and thus cause unreasonable cost (£51m since 2018) to consumers. While correct, excessive prices charged by wind farms to reduce output are a much more significant problem, resulting in much higher total costs for consumers, exceeding for example, £100m in 2023 alone.

On 23 October, 2023, REF sent a letter to Ofgem reporting a possible breach of the Transmission Licence Constraint Condition by Moray East offshore wind farm.  Apart from a belated acknowledgement of receipt of the letter on 4 January 2024, we have heard nothing further, so today publish the contents of the letter to Ofgem:

Summary

On its website the Moray Offshore Windfarm (East), known as Moray East and comprising one-hundred 9.5 MW turbines located off the North East coast of Scotland, describes itself as a “highly competitive offshore wind project”.

It is certainly notable for its extremely high levels of income, over £1 billion since it began generating in June 2021 and up to July 2023, with a strikingly high average of £234 per megawatt hour generated, well in excess of the average price of £168/MWh, received by gas-fired generators in the same period.

Renewable Energy Foundation has published two substantial studies of wind farm economics by Professor Hughes, the latest of which appeared in 2020. The present study applies the same principles to the analysis of large, utility-scale, solar generation in the United Kingdom and in the United States. Inquiries regarding the study can be made to This e-mail address is being protected from spambots. You need JavaScript enabled to view it .
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Attachments:

Economic-Solar-Generation.pdf

Payments to wind farms to reduce output are an ongoing national scandal, with the cost to consumers now totalling well over £1 billion since the payments began in 2010.

We have repeatedly observed that the prices charged by wind farms to reduce output not only routinely exceeded the subsidy income lost when constrained but were hard to justify in any case. Grid congestion preventing dispatch is a foreseeable commercial risk and the windfarms should not be compensated at all for such an eventuality.

However, it has been accepted by government and the regulator that such compensation – for lost subsidy – should be paid.

However, in recent months Scottish wind farms that are not in receipt of income support subsidy, so called “subsidy-free”, wind farms have also been charging the electricity system operator to reduce output when generation in Scotland exceeds grid capacity and local demand.
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Attachments:

UnsubsidisedConstraints

Large volumes of wind energy are being discarded in Scotland in order to preserve grid stability, with a fleet average of over 13% of generation constrained off in the years 2015 to 2021, inclusive, with a high of 19% of generation in 2020. Some wind farms have been discarding between 20% and 50% of their output, while being rewarded with generous constraint payments from the electricity consumer for doing so. The reductions in environmental benefits are not given adequate weight in the planning system, where the low marginal benefit of additional wind capacity appears to be poorly understood. This blog offers detailed data on the volumes of wind energy constrained off at a fleet level in Scotland between 2010 and 2021, and for every individual wind farm in 2020 and 2021.