Decarbonising the British electricity system is going to be a bumpy ride.

Reliance on weather-dependent generation sources by definition means greater price volatility. When the bulk of electricity is produced by inflexible assets with highly correlated output, the power market will experience ever more dramatic swings. So-called ‘price cannibalisation’ – where market value falls as more renewable capacity is added to the system – is morphing from academic theory into market reality. And as gas is pushed further out of the power stack by renewables, price-setting gas turbines will need to recover fixed costs over fewer running hours, meaning more extreme spikes when wind and solar generation falls short of demand.

For now, volatility is not a primary concern for North Sea wind projects. The Contracts for Difference (CfD) support regime protects renewable generators from wholesale price signals. Wind farms receive a top-up on the wholesale power price up to the value of a pre-set strike price. When the wholesale price rises above the strike price, the generator pays back the difference.

Shielding generators from price movements provides revenue certainty and reduces the risk profile of renewable project investments, lowering the cost of borrowing – a major component of the levelised cost of energy (LCoE) of wind. Long-term certainty provided a route to market for some 27GW of new capacity and delivered ever-lower CfD auction clearing prices in the first four allocation rounds since the scheme was introduced in 2015, to the benefit of consumers.

But this protection is creating perverse incentives and costly outcomes that are starting to erode the cost savings of the CfD. Balancing the Great British (GB) power market is becoming more onerous when an expanding slice of the generation fleet is rewarded for dispatching electricity as often and long as possible, regardless of prevailing market conditions. An offshore wind farm will receive the top-up to the strike price so long as the wholesale reference price remains above zero, which incentivises more supply even as the market is becoming saturated and signalling an imminent risk of imbalance.

Perverse incentives

Linking remuneration to output without accounting for system balancing costs cannot continue indefinitely. National Grid ESO (NGESO), the system operator tasked with balancing the grid on a minute-by-minute basis, must take ever-more extreme interventions to counteract the CfD’s incentive to maximise generation at all times. For instance, to curtail a North Sea wind farm when the system is oversupplied, NGESO would need to pay that generator more than the value of the CfD top-up to do so.

Shielding wind farms from market signals also encourages operators to schedule maintenance during low wind periods when, ironically, the system is likely to require additional generation. Aligning maintenance with systems requirements would mean scheduling downtime during windy periods of slack demand when the facility would otherwise expect to be maximising revenue generation.

Other problems are becoming apparent. When wind speeds turn out to be lower than forecast, there is no way for a CfD-backed generator to offset the reduction in generated volumes by capturing higher prices typically experienced during such periods. By contrast, a ‘merchant’ wind farm selling power directly into the spot market can more easily manage this volume risk.

Low temporal value electricity

The growing phenomenon of price cannibalisation is reflected in the lower prices that renewable generators can achieve in wholesale markets.

SmartestEnergy, a renewable electricity aggregator and B2B energy supplier, says “capture prices” for wind are declining compared to the N2EX baseload power price. The discount occurs because wind farms generate at the same time and thus “capture” only the lower prices in the day-ahead market, in contrast to baseload generators that dispatch around the clock – including those periods when the wind does not blow.

The “capture discount” for wind widened from -£2.10/MWh in winter 2018 to -£18/MWh in winter 2021, according to SmartestEnergy. This represents a -13% discount to the baseload price and is equivalent to roughly 40% of the value of the strike price for offshore wind farms that won a CfD in the fourth allocation round.

Greencoat UK Wind PLC, a FTSE 250-listed renewable infrastructure fund that invests in operational UK wind farms, reported an 11% capture discount in its 2022 financial results, compared to a 12% discount the year prior.

This phenomenon explains why offshore wind farms need a CfD in the first place. Generating ‘merchant’ – i.e. selling power directly into an exchange – exposes a project to a level of price risk that is unacceptable to lenders unless it can be mitigated by an alternative route to market, such as a fixed long-term power purchase agreement (PPA).

Unfortunately for offshore wind, the sheer scale of North Sea projects makes them unsuitable for PPA offtakers. The volume risk that arises when production falls short of forecasts requires the offtaker to buy back the difference in the open market. This imbalance cost is manageable for a PPA counterparty to a 50MW onshore wind farm or solar PV array, but is an order of magnitude greater for a 2GW offshore wind farm. No aggregator, utility or corporate buyer is going to offer a fixed PPA for the entirety of this volume of power, which means offshore wind farms are – for now, at least – stuck with the CfD as their primary route to market.

Through the looking glass

The capture discount is not a major problem for CfD-backed generators because they are topped up to the strike price – so long as prices do not turn negative. But since the fourth CfD allocation round, offshore wind farms will not receive the CfD top-up for settlement periods when the day-ahead reference price drops below zero.

Negative pricing is likely to become more frequent, posing a major headache for financing North Sea offshore wind farms. Simon Gill, an independent energy consultant who has undertaken extensive modelling of the GB power market, says negative prices could occur in the day-ahead market more for than 10% of all settlement periods.

“It could be as much as 25%, depending on how much flexibility we are able to introduce to the system,” he told efwd. “So for a quarter of the time you risk losing the CfD uplift and the electricity you are generating having no economic value.”

Going behind the meter

Commonplace negative pricing is both a challenge and an opportunity. Co-locating a wind farm with behind-the-meter storage or a hydrogen electrolyser is one workaround that enables the turbines to keep spinning. Dispatch can then be targeted at high price periods or into a different commodity market, such as hydrogen for green steel production. Similarly, bilateral trading arrangements could be developed to allow a wind farm to sell to a third party at an offsite location.

Currently, however, system operator NGESO is not equipped to deal with such arrangements. For example, when day-ahead prices turned negative on 29 December 2022, it expected the typical ‘cliff edge’ pattern whereby all CfD-backed generation shuts down. But analysis by Regen found a large batch of North Sea wind capacity (believed to be operated by Ørsted) unexpectedly fired up while prices were below zero – possibly because they had trading arrangements with an overseas counterparty in a continental European market with unmet demand, or with an energy supply company promoting an agile tariff.

“Clearly it is right to look at how subsidy schemes may be distorting market behaviour, producing an uneconomic response. [But] when renewable energy is in abundance there will be commercial opportunities we want market participants to take advantage of… even if this produces greater system balancing volatility,” Regen said in a letter to Department of Energy Security and Net Zero (DESNZ).

Rather than curtailing the market, the answer is to create markets for flexibility services that give ESO new tools to manage the system, Regen said. It also requires investment in building up ESO’s forecasting, dispatch and balancing capability through digitalisation, system modelling and automation.

Carrot or stick – or both?

These problems are well understood by the UK government, which is seeking to reform the CfD as part of its sprawling Review of Energy Market Arrangements (REMA) process. REMA identified all of the above issues and sought views on how to strike a balance between the lower financing costs arising from shielding CfD generators from market signals, and more efficient system operation by exposing them to real-time price movements.

REMA triggered a slew of proposals from think-tanks, consultancies and trade bodies. DESNZ is currently picking through these and is expected to launch the next phase of REMA consultation imminently. However, a less discussed aspect in all of this is the potential role of using carbon pricing rather than subsidy mechanisms to promote renewable sources.

A recent policy paper from the Regulatory Assistance Project (RAP) found that subsidies perpetuate price cannibalisation and impede investment in merchant projects. This “locks policymakers into a further cycle of subsidy, which must encompass more and more sectors — such as flexibility and energy efficiency — to ensure a level playing field.”

“Price cannibalisation is a feature of excessive reliance on subsidies to roll out variable renewables,” the study states. Instead, it proposes a hybrid approach of robust carbon pricing combined with “smart” design of renewables support that unlocks flexibility, preserves market signals for renewables deployment and supports a least-cost transition with minimal government intervention.

“With such an approach, price cannibalisation need not be inevitable: the distribution of hours per year in which wind and solar recoup their costs need not change radically as the carbon budget is lowered,” RAP concluded.

The UK is not quite set on this trajectory, although REMA offers an opportunity to pursue it. Carbon prices on the UK Emissions Trading Scheme (UK ETS) have collapsed dramatically since March 2023, opening a large discount to the EU ETS. But REMA ruled out changes to carbon pricing policy from the outset because the UK ETS covers a wide range of economic sectors beyond electricity generation.

DESNZ anticipates that “the carbon price will increase as the economy decarbonises” but is focussing on “additional policy levers” to deliver its target of a decarbonised power sector by 2035.

Without intervention to shore up the UK carbon price, REMA risks pursuing subsidy-focussed solutions that both exacerbate volatility and expose North Sea offshore wind to unmanageable price risk. Clearly the status quo is becoming untenable, but international investors will need to see evidence that the ‘medicine’ is not worse than the disease it is intended to cure before committing capital to the next chapter of North Sea wind development.

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