Why short-term high wholesale prices aren’t the key driver of domestic energy bills

The current cold snap across most of western Europe has resulted in high wholesale electricity prices. Observed prices in the GB wholesale market are typically higher than those in neighbouring electricity markets, and here we provide an explanation of why this is likely the case but also why short-term periods of very high wholesale prices are not the primary driver of most end users’ energy bills.

Looking at data for GB wholesale prices on Monday 12 December shows that electricity trades completed on Sunday 11 December for the following day reached in excess of £2,500/MWh for the evening period (7pm ). For the same half-hour period beginning at 7pm on Monday prices observed for France, the Netherlands and Belgium were closer to £500/MWh – so why the large difference?

Across GB, and neighbouring markets, energy demand is above seasonal norms as temperatures are well below average for this time of year. The consequence is of course that heating will be on for longer and must work harder to meet desired temperatures, and as gas is the primary fuel consumed to heat properties in GB this has pushed up gas demand. National Grid Gas forecast total daily demand for Monday was 394 million m3 (mcm), some 87 mcm higher than the seasonal normal.

The squeeze on gas directly drives electricity prices here in GB as margins, the additional available power generation capacity over demand, are manageable but low. This is primarily because of low wind speeds, especially over the North Sea where much of our offshore wind is located. Without high output from wind power, we are reliant on other generation sources, and as gas-fired generation forms the lion’s share of available generation that has the flexibility to increase and sustain output, it is here that the market turns to during these tighter periods.

As we know, gas wholesale prices across Europe are exceptionally high as a direct result of the war in Ukraine and the resulting large reduction in Russian supplies flowing into continental Europe.

The market though has the option of importing electricity via interconnectors that link us to neighbouring markets (Norway, France, Ireland, Netherlands, Belgium). To attract electricity imports the GB wholesale electricity price must be sufficiently high to encourage additional generation across the continent, although the volume of imports is capped by interconnector capacity and their availability. Reductions in French nuclear availability, which typically provides two-thirds of France’s power demand, has worsened the electricity supply picture in Northwest Europe and meant GB power prices have been at a premium to secure imports.

By our estimates, without electricity imports from the continent much more expensive domestic generation would need to be called upon, such as requiring old coal-fired power stations to operate to meet the evening peak. This looked as if it could have happened early on Monday, but the coal-fired stations were stood down at lunchtime.

Although we are only describing wholesale market conditions for a specific day, this short-term focus masks how prices for electricity to be delivered in the first three months of 2023 have also risen significantly over the last month. Electricity wholesale contracts for January 23, February 23 and March 23 are around 20% higher than they were a month ago, and the contract for Summer 23 (April to end of September) is one-third higher, largely driven by the market seeing gas supplies into Europe and GB for next year being costly for the reasons we have seen this year (that is, largely a result of countries looking to replace Russian supplies).

While this of course has huge implications for energy affordability, triggering governments across Europe to intervene to lower-end bills to various degrees and via different mechanisms, it does point to the market working as intended. The GB electricity market (and indeed markets across Europe) are based on marginal pricing where the most expensive power station needed to operate at any point in time sets the market price. As this happens to typically be gas-fired generation during times of high demand, the consequence is in a high gas price environment we see high electricity prices – especially for volumes of electricity traded to meet peak winter evening periods.

As the capacity margin declines, as it does on cold still evenings, the resource we require to meet demand becomes scarcer and pushes up prices. Indeed, scarcity pricing is embedded within the GB electricity market design, where Ofgem introduced the principles of scarcity reflective pricing into the GB market in 2015 following the Electricity Balancing Significant Code Review. The idea was that developers of flexible generation needed to be confident signals for flexible power generation would be available in the market or to the Electricity System Operator to incentivise efficient dispatch and investment.

So, while cold snaps rightly attract attention on how the system will cope in the short term, and how market prices respond accordingly to the increased scarcity of generation to meet demand, the typical consumer will be relatively shielded from these short-term periods of very high prices as suppliers will be buying the bulk of their electricity well in advance. As we have commented before, it is the outlook for prices over the coming six months that will be the largest driver of end user’s bills (with or without government support), but suppliers that do have to purchase electricity in the short term at these exceptionally high prices (of which no doubt there will be more this winter) will likely face cash flow or credit impacts.

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