In the year and a half from the beginning of 2020 to July 2021 UK power day-ahead prices effectively doubled, and everyone from suppliers, three of whom have closed in recent weeks, and another two today: Utility Point and People’s Energy, to end consumers facing another increase in the retail price cap have felt the impact. But the past week has seen prices double again and with prices exceeding £400 /MWh.

day-ahead electricity prices

The question is why is this happening and will these price levels be sustained? And what does this mean for the market?

Tight generation margins driven by low wind and unplanned outages

Power prices continue to be supported by high gas and carbon prices, and when combined with tight system margins due to low wind output and low interconnector availability, this puts significant pressure on prices.

While day-ahead prices on the N2EX exchange breached £400 /MWh, OTC prices have been even higher. According to S&P Global Platts, day-ahead baseload prices for delivery on 14 September reached £540.15 /MWh, up from £171.15 /MWh for 10 September. Platts Analytics is forecasting October baseload power prices to average around £122 /MWh, and expects market tightness to continue into Q1 2022, with average prices rising to £126 /MWh – more than double last year’s winter average of £55 /MWh. Intraday prices have been recorded a £1,750 /MWh on N2EX, and prices have become so volatile that EPEX doubled the price cap for UK intraday power prices to £6,000 /MWh.

At the same time imbalance prices have hit a record £4,037.80 /MWh with several generators bidding into the Balancing Mechanism at £4,000 /MWh on 9 September. Last week units at West Burton A were accepted into the Balancing Mechanism at £3,950/MWh, while Uniper’s Grain 6 combined-heat-and-power plant was accepted at £4,950/MWh. Even this evening, West Burton was accepted at £4,000 /MWh.

“Power prices are being driven by high gas prices but when prices start to get really, really high, it’s being driven by scarcity, rather than just the underlying cost of production. When we have scarcity events and wholesale prices spike, the cost is going to go up for consumers,”
– Marlon Dey, research lead for Great Britain at Aurora Energy Research

UK month ahead gas prices have increased from 28 p/th a year ago to 145p /th on 10 September, with NBP futures rising above 150 p /th for the first time ever. Gas prices continue to be supported by low storage levels across Europe, competition with Asia for LNG cargoes, and concerns over supplies from Russia. Although coal prices are also rising (from US$ 140 /MT in late July to US$ 170 /MT in September), gas-to-coal switching is a possibility with generation economics from coal improving significantly. This is despite all-time highs on the (admittedly still new) UK ETS of £54.05 /tCO2.

“There’s a lot of nervousness in the market. It’s been a long time since Europe has entered a winter with such little gas in store,”
– Thomas Douglas, ICIS

The UK’s domestic gas production has been significantly lower this year due to a heavy schedule of planned maintenance and delays to new projects such as Tolmount which was expected to come onstream in July and is now delayed until the end of the year after faults with off-shore electrical systems were found during final commissioning and testing.  UKCS production year-to-date is down by 5.7 Bcm from the 25.9 Bcm produced in the same period last year.

The UK has also seen a drop in LNG imports as higher JKM prices attracted cargoes into the Asian markets – with imports of 10.4 Bcm YTD, 4 Bcm lower than last year.

In the electricity market, five nuclear units are currently offline, four for un-planned outages, removing about 3 GW of available generation and there is a partial outage on the 2 GW IFA interconnector with France reducing capacity by 1 GW until 17 September. CCGT availability has been low since the beginning of the month aside from the on-going absence of the two 850 MW Calon units, although plant has steadily come back on line in recent days, and there have also been unplanned outages at coal and biomass units.

“It’s very unusual for this time of year. This is the sort of thing we start to see when we get cold snaps. The worrying thing is that this is happening now, in September. We’re approaching a winter with not too much margin for error,”
– Murray Douglas, head of European gas research at Wood Mackenzie

electricity system demand

Demand began to rise again at the start of September as the holiday period came to an end, and people started returning to workplaces after the pandemic.

It’s time for the Government to act

With three suppliers having exited the market in the past few weeks, and a further two announcing their closure today, there are expectations that more will follow, particularly next month with the late payments deadline for the Renewables Obligations, an annual stressor for suppliers paying in to the buyout fund.

The problem all suppliers are facing, although it affects smaller suppliers more with their reduced access to hedging, is that the retail price cap is only re-set twice a year. With prices rising as rapidly as they are, suppliers will be forced to sell at a loss, which will inevitably push more of them out of business.

Suppliers can offer fixed price deals that are above the level of the price cap, and indeed, this is currently happening, but for suppliers that are unable to hedge in the markets, fixed price deals represent a risk. However, against a backdrop of capped variable tariffs, the smart play might be to try to move customers onto expensive fixed price deals in the hope that they switch to another supplier – shrinking may be the best survival strategy this winter.

electricity procurement strategies

Access to hedging has long been a problem for smaller suppliers due to a combination of onerous credit requirements and difficulty in trading the small sizes needed to manage shape risk. Due to the difficulty in managing shape risk, as well as the additional systems and back office operations involved in market trading, some small suppliers opt not to have an active procurement strategy and instead simply run imbalance positions and pay the cashout price for the electricity that they deliver to their customers.

Although imbalance prices can rise rapidly, the typically only remain high for a few settlement periods, so the risk is considered acceptable, and the majority of the time, this approach is cheaper than buying in the wholesale markets. However, as the analysis below shows, in periods of market tightness and high price volatility, this approach become much more expensive than buying in the day-ahead market, more than overwhelming the savings made the rest of the time.

“In no other sector is the government forcing a loss on the supplier. The cap is fixed like some kind of tablet in stone from God; the market doesn’t work like that. Whether it’s quarterly or monthly; it needs to be calculated more frequently,”
– Steven Day, co-founder of Pure Planet

This makes life even harder for small suppliers – if they lack the resources to buy in the day-ahead markets and are forced to pay the cashout price things can get very expensive very quickly. The existence of the price cap, and the low frequency with which the cap is revised, exposes them to the risk that they will be unable to pass these costs through to consumers.

According to former Ofgem CEO, Dermot Nolan, consideration was given to re-evaluating the price cap every two or three months but the idea was deemed inappropriate. This decision needs to be re-visited as a matter of urgency, and the case for abandoning the cap altogether is growing. The fact of low energy margins is now being widely reported in the press – if consumers can be persuaded that suppliers are not profiteering at their expense and that they face genuine challenges, they may be prepared to accept the withdrawal of the cap.  

“There’s certainly a case for moving to every four or two months now. It would probably avoid distortions, but the question is would consumers tolerate prices changing every month,”
– Dermot Nolan, director at Fingleton, former Ofgem CEO

Removing the price cap would remove a major source of risk for suppliers in the short term, and although there are arguments that market entry should be made harder by requiring suppliers to be more financially resilient, even the best resourced firms will struggle in these markets. However, in the short term, large numbers of supplier failures will create chaos, and Ofgem may find it difficult to find suppliers willing to take on SOLR responsibilities, particularly when compensation for honouring customer credit balances can take a long time to materialise.

The other issue is that against the backdrop of higher taxes to fund the NHS and social care, these energy price rises could not come at a worse time. Life is about to get very expensive for consumers, pushing more of them into fuel poverty. The chances of making meaningful progress on net-zero ambitions that require investment from consumers will fall as those investments become less affordable.

While there is no magic cure for rising global gas prices, there are things the Government can do to address the risks the market faces:

  1. Reform the retail energy market to remove non-supply obligations from suppliers
  2. Act on greenwashing to restore confidence in the sector
  3. Abolish the price cap, which creates un-necessary pressures for suppliers
  4. Take meaningful action on the growing capacity deficit

On this last point, the closure of the remaining coal plant in the next few years, and the likely earlier than expected closures of the aging nuclear fleet are all likely to happen before Hinkley Point C opens. If the Government wishes to nip these damaging price trends in the bud it needs to act on the growing capacity deficit in periods of low wind generation.

Approving Wylfa Newydd should be an easy choice, and consideration should be given to allowing the remaining coal plant to remain open at least until Hinkley Point C is able to open. This would be very controversial, but could be justified on the basis that when the Government decided they should close there was an expectation that the AGR fleet would remain open until new nuclear came online. As this is now looking less likely, something has to give.

The alternative is a renewed focus on gas, but this is hampered by the fact that since the closure of Rough in 2017, the UK has not had a large-scale seasonal gas storage facility. Developing a new facility of that size in the time available would be expensive, and relies on suitable sites being available. Keeping the last remaining coal plant open for a few extra years would be a cheaper and more reliable option, and a special reserve product could be developed to ensure it only ran when absolutely necessary to mitigate the political risk of the decision.

In the end, the three prongs of the trilemma are not equal. Security of supply is the most important part of the equation – in the end, people will be willing to pay higher prices if the alternative is supply disruptions, but only if other options have been exhausted. At some point high prices will become politically untenable, at which point all bets will be off on net zero. It’s time to restore balance to the market in more ways than one. 

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