Wholesale Energy Prices: Oil, Natural Gas and Electricity as at 1st June

In this article, Dominic Whittome covers recent changes to wholesale energy prices.


Crude prices halved as the oil market experienced an output surge and a collapse in global demand. So great was the imbalance that West Texas Intermediate momentarily traded at negative prices, below $30/bbl at one point. The International Energy Agency is now predicting that the pandemic will lead to the largest reduction in world energy infrastructure spending on record: an annual reduction of 30% in fossil fuel and 20% general energy investment. The IEA has also stated, however, that fossil fuel demand may rebound sharply as the crisis passes. It observed how China and certain other Asian nations had placed recent orders for new-generation coal-fired power stations.

In some respects, the oil market has hit a perfect storm: a coincidence of a sharp supply contraction and increased oil production export policy, which Saudi Arabia had already initiated before the effects of the pandemic were known Seeking to reassert authority over fellow OPEC states and non-OPEC producers alike, including Russia with whom talks over output reduction co-operation had broken down barely three months before the economic impact of the pandemic became apparent. The tactic has had a far more negative impact on oil prices and with it an adverse effect on investment which has been acutely lacking in Iran, Iraq and Libya, the latter producer also having to deal with Russian backed insurgence, limiting its export capability further. It may not sound terribly scientific but the proverb ‘the greater the fall, the sharper the rebound‘ could be possibly be true in this extreme instance. Throughout history, oil prices have instigated their own cycle: low prices reducing investment and lower medium-run lower output and consequently higher prices longer-term; and vice-versa. The oil market is certainly in the doldrums now, but prices could soon recover, potentially past $50/bbl, once demand returns closer to pre-pandemic levels.

Natural Gas

Forward Year gas prices fell by another 18% to close below 30 pence a therm for the first time in over 15 years. The gas market fell amid reduced LNG demand by South East Asian buyers as well as major European users and some seasonally very high inventories at gas storage facilities across the Continent, with many units closing out the winter period over three quarters full. This will have added to a sense of over-supply and will also limit contingency gas purchasing over the summer months by the major energy utilities. Looking further ahead, the pandemic has compromised gas infrastructure investment, just as it has in the case of oil. This is notably the case in the US, where key LNG export projects have already been mothballed and in Russia too; whose vaunted 16 bcm/year Blue Stream pipeline into Germany is looking increasingly in doubt, now having to contend with lower-than-projected gas prices as well US sanctions directed at the project, which were put in place before the new economic uncertainty hit home.

However, gas prices follow a cycle which is in many ways analogous to the crude market. In real terms, wholesale gas is now trading at its cheapest levels in over 20 years. If economic activity picks up and oil prices continue their recent, if muted, recovery, then we could see forward gas prices enter a recovery phase, especially if we see a policy shift is support of new gas-fired power plants, seen necessary in order to balance inflexible low carbon electricity generation in future. One of Europe’s newest coal-fired plants is the 1.1 GW Datteln 4 plant in North Rhine-Westphalia, Germany, which will burn lignite. Whether or not this example, among other brown coal and gas projects in Europe, prompts a rethink of the role gas-fired generation should play in Britain remains to be seen. Recognised Gas Carbon-Capture and Clean-Coal generation solutions have proved elusive or prohibitively expensive so far. However, innovation and also test projects are now progressing. These developments, as well as a future Hydrogen Economy, taken together could affect the long-term outlook for gas.


Power prices followed the gas market down, falling 10%, although base-load prices have started to pick up towards the late end of May amid signs of some return to normality in Continental Europe. On the supply side, the concern is over the summer availability of nuclear and hydro electric volumes should the latest meteo forecasts of a dry European summer prove to be accurate and reservoirs fall short of the cooling capacity required for such power plants. With wind output likely to be very limited and thermal generators constrained in the short term, there is scope for power prices to recover further, even if the market is over-supplied and subject to sudden dips just at the moment. Meanwhile, the last quarter saw a substantial portion of Britain’s existing nuclear fleet being put up for sale. British Gas’ owner, Centrica, already had plans to sell its own 20% stake in the UK’s eight operational reactors but has now been joined by its partner, EDF, which is seeking a buyer for 30% (or possible half) of its 80% stake. How soon a pension fund or other buyer can be found is anyone’s guess. However, end-of-life nuclear acquisitions involve huge unknowns, decommissioning being just one.

All of the UK’s operational reactors are now over 35 years old and operating at or beyond their original design lives; the one exception being the pressurised-water reactor at Sellafield, which could theoretically still run past 2030. However the other seven will need to shut, well before the end of the decade and the closure of one power station could be imminent. Leaving supply-availability to one side, the UK power market is likely to see increasing day-to-day and intra-day price variations as balancing volumes command a premium. This will increase the cost of load-shape in business electricity contracts just as capacity prices also see sharp increases, partly to finance new-build nuclear and other low carbon projects under the CfD surcharge to power bills. If/when these prices climb, electro-intensive users will look to mitigate by shaping the electricity themselves as much as possible, potentially through on-site generation, storage, demand side management and, especially, energy conservation. The commodity price for base-load power certainly looks subdued. The electricity market was always going to be far less affected by this pandemic than the oil market, which is reliant on demand for automotive fuels. Nevertheless, should any scarcity in the availability of flexible electricity become apparent, this market could still turn quite quickly if and when that may happen.

About the Author

Dominic Whittome is an economist with 25 years of commercial experience in oil & gas exploration, power generation, business development and supply & trading. Dominic has served as an analyst, contract negotiator and Head of Trading with four energy majors (Statoil, Mobil, ENI and EDF). As a consultant, Dominic has also advised government clients (including the UK Treasury, Met Office and Consumer Focus) and private entities on a range of energy origination, strategy and trading issues.

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

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