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Suggested reforms offer best chance to deliver GB net zero power market by 2035 LONDON, February 01 –...Read More
2 February | Online Recent extreme price spikes for the GB power market have triggered key discussions...Read More
Senior Analyst and report author Jonathan Sims said: “Our findings show the extent to which the global gas market has over the past two years skewed British power prices to levels unreflective of the technological makeup of today’s generation mix.“While continuing with marginal pricing for wholesale power market design is preferable to ensure significant changes do not dent investor confidence in the renewables sector at this crucial juncture, government must protect against any future gas price spikes pulling power market prices up with them.”
Power Analyst and report author Lorenzo Sani said: “A split market, by effectively putting a floor on wholesale prices, removes the price signals needed to deploy the flexible technologies that can ensure the stability of a renewable-based power system. A net-zero power market must provide incentives for the clean technologies that are currently struggling to be profitable: flexibility providers (e.g. battery storage and demand response) will support system stability while electrolysers would take advantage of the low-price periods to produce green hydrogen to be used during cold winter days."
Recent extreme price spikes for the GB power market have triggered key discussions over whether the time has come for a shift in the way that electricity generation is traded and priced in the country.
Marginal Call estimates what Great Britain’s wholesale market electricity costs would have been if prices were calculated via a “split market” that separates the pricing of power produced by variable supply of renewables, from other sources, as opposed to the marginal pricing design the market currently operates under.
When calculated this way, total net power procurement expenditure over 2021-22 turns out around £7.2 billion lower, representing what could have been saved if measures had been in place to protect against gas market price spike influence on the power market.
Market split design would however only result in cheaper bills for consumers over the longer-term if gas prices remain at high levels for the rest of the decade (fig 1), while pricing signals for flexible power sources such as battery storage would be weakened.
Figure 1: Gas prices would need to remain high for market split design to achieve long-term cumulative cost savings
Instead, the analysis suggests policy measures such as utility hedging obligations for future fuel needs to reduce exposure to high gas prices, and reform to contracts for difference (CfD) agreements to lower bills.
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- GB’s wholesale power market grid procurement expenditure over 2021-22 was not reflective of the makeup of technologies supplying electricity. Estimated grid costs turn out more than £7 billion lower on a net basis when calculated instead using a generation-weighted average of technology output over that period.
- Policy makers should consequently introduce measures to protect against future gas market price spikes which skew power market prices under marginal pricing design. These could include imposing hedging obligations on utilities for their future fuel requirements.
- The continuation of marginal pricing is still preferable to a significant shift in market design. A complete change in the market design used for the pricing of GB electricity generation may risk denting investor confidence in renewables and low-carbon forms of flexible generation by creating renewed uncertainty over project revenues. This could consequently threaten the UK’s 2035 deadline for completing power sector decarbonisation.
- Alongside measures to counter any future gas market price spikes, the UK Government should also restructure its Contracts for Difference (CfD) support scheme for low-carbon generators. Basing future CfD top-up payments on eligible firms’ overall combined revenue streams would ensure investor confidence is not impacted by the risk of not receiving payment during periods of zero or negative prices in the wholesale market, while the adoption of contracts from the point of first operation of a project should be made mandatory.