Link between gas and power prices rapidly diminishing

Unabated gas generators are expected to set wholesale prices less than 10% of the time by 2030, the government has forecast, significantly weakening the link between gas and electricity prices.

The Department for Energy Security and Net Zero (DESNZ) said this would happen in its higher demand scenario in which unabated gas generation would then become the marginal plant in the wholesale merit order in fewer than 5% of hours by 2035.

Gas generation was the marginal price-setting plant in almost 80% of hours during 2020. DESNZ said this proportion is expected to fall to less than 45% next year.

The department included the forecast in the second consultation document for its Review of Electricity Market Arrangements, which has ruled out a number of potential reforms that were previously on the table.

These included proposals to split the wholesale market into two separate markets for dispatchable assets, such as gas-fired power stations and batteries, and renewables, or create a Green Power Pool that would operate alongside an otherwise relatively unchanged wholesale market.

These changes would limit the ability of renewable generators with low short-run marginal costs to capture “intramarginal rents” during periods when gas generation is the marginal plant in the merit order, thereby weakening the current link between gas and electricity prices.

Pressure to decouple gas and electricity prices has grown following Russia’s invasion of the Ukraine and the subsequent gas crisis, which handed large windfalls to renewable generators without fixed-price Contracts for Difference (CfDs).

Last year, the government introduced the Electricity Generator Levy – a temporary 45% tax on receipts above £75/MWh – to clawback some of these gains. The levy will remain in place until 31 March 2028.

DESNZ has now dropped proposals to address this issue on an enduring basis by either splitting the wholesale market in two or creating a ‘Green Power Pool’. The latter would provide the option for renewable generators to secure long-term contracts, with any remaining generation spilling over into the main wholesale market.

The department said there are “significant risks” with both models: “In particular, as electricity is a fungible commodity (electricity generated from a renewable generator has the same properties as electricity generated from a fossil-fuel generator) and can be traded multiple times before it reaches the end-consumer, trading between the two markets (in both models) may result in the lower price in one being driven up towards that of the other section of the market during periods of scarcity.

“This would likely result in benefits accruing to intermediaries (such as energy traders) rather than consumers, fundamentally undermining the case for these approaches.”

Furthermore, DESNZ said neither option could be implemented before the late 2020s at the earliest, by which point gas generation would already have a significantly diminished role in setting wholesale prices.

In its higher demand scenario, the department said around 70% of generation would be covered by CfDs or the Regulated Asset Base model for nuclear by 2035 – up from 10% currently.

It has also discounted the possibility offering CfDs to existing renewable generators – an option which was originally proposed as an alternative to a windfall tax – after deciding that any short-term savings would be offset by locking in current high prices over the long term.

CfD changes

However, DESNZ is continuing with proposals to modify CfDs to make contracted generators more responsive to the needs of the electricity system.

The department said the current design of the mechanism incentivises generators to maximise output with little regard for when and where it is produced.

They have little incentive to locate in areas where there is less renewable generation, and during network constraints, they must be paid enough to recoup lost subsidies, discouraging them from providing ancillary services and distorting the merit order in the Balancing Mechanism.

They are also incentivised to bid into the wholesale market in the same way, leading to “herding behaviour”. Generators that secured contracts from allocation round 4 do not receive support payments if the day-ahead power is negative, resulting in a “cliff edge” that can make it difficult and expensive to manage the electricity system.

DESNZ has discounted the options of a CfD with a strike price range, whereby it would fluctuate within a set range, a cap and floor mechanism similar to the support regime for interconnectors. It said the former would increase overall strike prices, whilst the latter could distort operational behaviour and would present significant opportunities for gaming.

It said the two main options it is still considering would break the link between actual metered generation and top-up/clawback payments by paying them on the basis of their potential to generate.

The first would pay generators on the basis of their “deemed” output – the maximum amount of electricity they could theoretically produce given live weather conditions. DESNZ said this option would continue to protect generators from price risk, could potentially add some protection from volume risk, and could enable the removal of the negative pricing rule.

However, the department also cautioned that the deeming methodology would need to be carefully designed to avoid overcompensating generators and creating opportunities for gaming. It said adaptations might also be required to prevent deemed CfDs from dampening locational pricing signals if it decides to proceed with zonal pricing.

The second option would pay generators a fixed amount on the basis of their capacity, meaning they would operate on merchant terms, “optimising their trading and operational strategies to maximise revenues across markets.”

“This model would expose generators to both volume and price risk on a day-to-day basis, but also provide them with a degree of revenue certainty to support investment decisions,” it explained.

“Doing so should provide similar operational and investment benefits to the deemed CfD, although we would expect the market signals driving those benefits to be even stronger under this model with less complexity and scope for gaming.”

DESNZ said it would expect developers to reflect anticipated market revenues in their bids, although some developers may seek to de-risk their investment through a high capacity payment.

It said a consumer protection mechanism would also be needed to prevent generators earning excessive returns when wholesale prices are high. This could mean requiring generators to return some or all of their revenues in excess of their administrative strike price.

DESNZ is additionally considering several supplementary options that could be implemented in parallel with, or instead of, payment structure reforms, the first being partial CfDs that would only cover a portion of generators total contracted capacity. The remaining portion would be operated on a purely merchant basis.

The department said it believes there could be an appetite for this option within the industry as several developers have already taken this approach by themselves. This would put more price risk onto both developers, potentially increasing the cost of capital and strike prices, and would also leave consumers more exposed to high wholesale prices.

DESNZ said further work is needed to establish whether these risks would be outweighed by the benefits of reduced operational and investment distortions for the portion of the asset not covered by the CfD.

Another option is changes to the reference price for calculating top-up/clawback payments such as a hybrid reference price that would be weighted between day-ahead prices and long-term prices from a month ahead to a season ahead.

The department said this would remove barriers to forward trading and increase incentives for generators to hedge a portion of their output ahead of time.

Finally, DESNZ is also considering introducing a locational element to CfDs as one of the alternatives to zonal power pricing. It said this option, by itself, is unlikely to send the locational investment signals it desires but could complement and have synergies with other options such as reforms to locational transmission charges.