In this article, Dominic Whittome covers recent changes to wholesale energy prices.
Oil markets rebounded. Brent prices rose over 20% at one point although the spot contract gave up some of its gains recently as worries over the 2nd wave pandemic weighed on the market. In the background, geo-political and upstream investment concerns over Middle Eastern supply remain. There is no end in sight for the shut-in of Iranian exports and there is rising concern over the export capacity of Iraq, Libya and Angola, where mounting political tensions and worsening infighting have thwarted efforts to reinforce war-damaged and aging infrastructure across the supply chain, from well-head production, pipeline transport, storage and offshore loading facilities. The sharp reduction in global demand this year has led to unprecedented oil inventories at or near full capacity, with a glut of crude cargoes still looking for a home. However, oil supply in non-OPEC regions has been curtailed and demand generally could see a rebound in years ahead, much of it within the region itself. Simply to illustrate, Egypt recorded a population eclipsing 100 million this year, just one example of rapid population growth across the North African and Middle Eastern region, which are on a steep oil demand trajectory. Should global demand pick up, the crude market may turn out to be tighter than the current headlines or short-term prices suggest.
Gas markets across Northern Europe recovered strongly up 28% over the period, in spite of the market going into winter with storage facilities across the Continent 85% full or higher still in some cases. Prices were said to have climbed amid agreed US-EU sanctions against Russia, which would threaten to delay or possibly block the completion of the huge Nord Stream 2 pipeline to Germany. However, with just 350 km to be finished, it is doubtful if this latest spat with Russia will finally affect the supply outlook for long. Gas prices traded at the National Balancing Point (NBP) may also be affected by any further weakening of Sterling versus the Euro. UK gas prices, traded in pence per therm, are strongly influenced by the arbitrage play between the NBP and Dutch TTF (Title Transfer Facility), which is the principal hub for the North European gas corridor and which is used to clear traded volumes in €/MWh. There are many factors in the mix. However were Sterling to fall to parity with the Euro, say, this would certainly feed through to the wholesale market and immediately to commercial prices here in the UK.
It is possible that the summer months may have been used to re-evaluate need for a new wave of gas-fired power stations, to counteract the impact of more intermittent renewable generation in the years ahead. We are already seeing evidence of this on the Continent with new coal/lignite-fired as well gas-fired generation projects being sanctioned to meet the expected demand for peak-demand electricity. Looking at just the few months ahead, wholesale gas prices will be most sensitive to demand (pandemic, general economy and weather-related – equally unpredictable); Sterling currency movements; background oil & gas prices and available supply from major North Sea, Russian and global LNG producers, among many other factors.
Base-load power prices climbed by a fifth; almost in tandem with energy markets generally. However the increase was muted, cut back in its tracks amid renewed uncertainty over the economy and electricity demand itself, which has fallen substantially across the UK and the Continent this year.
Supporting very long-term prices perhaps was the confirmed shut-down of the Advanced Gas-cooled Reactor at Hunterston B in Scotland, with other AGR closures now expected to happen sooner as a result. All of the UK’s currently operating nuclear power stations bar one employ the same AGR design and will have the same safe-operating design life; and most were built at around the same time during the 1980s. It is quite plausible a scenario for the UK to have just two nuclear power stations, at Sellafield and Hinkley Point, operating by 2029. It is not just an issue here but a concern on the Continent as well, typified again with one dominant design in a nuclear fleet which is older still, with many such plants having begun to be constructed in the wake of the Oil Crisis of 1974.
The medium-term supply outlook for electricity is stable and the market looks well-supplied for the time being, although a growing array of factors is at play which could influence base-load prices either way. Further, the Forward Market for electricity remains illiquid. This makes it difficult (and expensive, due to the high risk premiums resulting) for I&C buyers to lock into a forward contract price beyond a year or so. Prices along the forward curve are lacking in transparency and are also prone to sharp fluctuation. Equally, the intra-day Elexon and day-ahead/N2EX balancing markets have been exceptionally volatile of late, a trend that looks set to continue into the future as more renewable generation gradually comes online, requiring ever more urgent balancing actions by the system operator (National Grid) using its appointed market operator Elexon to requisition power from spinning reserve power stations and electric storage, all of which will come at a cost which will feed to consumers.
Consequently, more commercial users could be looking to install on-site generation and energy storage in future: to mitigate increasing brownout/supply-disruption risks, reduce net power purchases and buy the residual electricity on more favourable price terms than otherwise. This together with improved energy conservation, demand management and purchasing strategy will each have a role to play in mitigating rising non-commodity costs which already make up circa 65% of a typical business electricity bill. Such pass-through charges, the Climate Change Levy in particular, will continue rising, possibly on a much sharper trend, in order to support the new nuclear power station at Hinkley Point and future low-carbon projects.
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.
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