In this article, Dominic Whittome covers recent changes to wholesale energy prices.
Dated Brent has risen some 25% in two months, in a crude market rattled by deepening geo-political tensions worldwide and continuing worries about medium-term supply from embargoed Venezuela. There are also concerns over Iran, which is subject to US sanctions, whilst there are threats of upheaval in Nigeria and Sudan.
New US sanctions and talk of military pressure to remove President Nicolás Maduro have contributed to oil production falling below 1 million barrels a day, down from circa 2.5 million barrels just four years ago.
Venezuela only recently overtook Saudi Arabia to become OPEC’s largest player in terms of proven reserves. A well publicised ‘re-newel of vows’ or closer military accord with Russia will only have stoked tensions further. While global petroleum prices have had a good run, they have potentially further to go, especially if we see investor flight into hard commodities. Dated Brent remains well below its most recent $85/bl peak in October last year.
Short-term market changes and the geo-political situation may have caused a breakdown of gas price correlation to oil, with Forward Year prices down by eight per cent. Seasonal gas demand slipped back last month and the market has been well supplied to date.
Gas prices followed electricity down, for here the price convergence between these two commodities increased over the last year. On 1st Jan, 2018 forward gas prices stood at 46.60 p per therm, with electricity trading at £44.85/MWh versus 54.47 p and £56.18 today. One factor at play here is the carbon market. The second half of 2018 saw struggling nuclear output and renewable electricity both fuelling demand for fossil generation. This was chiefly offset by rising gas and coal-fired plant. Indeed fairly extensive new-build coal programmes are already underway in Poland and Germany.
In the short-term, elevating coal-fired plant further up the generation stack has served to increase demand for carbon permits. This contributed to soaring carbon prices on the EU Emissions Trading Scheme. In 2018, the prices of traded EUAs soared by over 400% at one point, from circa € 7.50/ tonne CO2 in January 2018 to current trading levels closer to €20. The carbon factor has increased the running cost of gas-fired plants in the UK, paradoxically undermining the economics of new-build plants which the country may need to maintain supply cover ahead, a point we can look at now.
In January, Hitachi cancelled its planned 2,900 MW nuclear power station project destined for Wylfra in Wales from 2027, hot off the heels of Toshiba’s own aborted 3,400 MW project in Cumbria.
Given the very price swap/Contract-For-Difference subsidies involved, it is perhaps tempting to think that the termination or suspension of any more nuclear plants will alleviate the pressure on future prices. However, the reality is probably much more sobering, because the non-fossil alternatives may well prove equally or more expensive, certainly in the electricity volumes which may needed.
The Forward Market may well be even more reliant on potentially expensive imports via interconnectors. These entail an additional security of supply risk. Although the UK has a healthy-looking pipeline of new interconnector projects, the existence of new cables is no guarantee of supply.
The cross-Channel interconnectors, new 1 GW and 2 GW wires from Holland, Belgium, Denmark and the six espected from France may each be subject to competition from Continental buyers when it comes to peak demand days. Although Norwegian and Icelandic exports may be dedicated to the UK mainland, the technical issues will remain here too, with volumes being exported over longer distances and at very high voltages to minimise transmission losses. Sub-sea networks generally involve sophisticated equipment which can fail, even with state of the art technology. Hence, this is simply a new element of risk which the UK market may have to grapple with, together with competition for supply.
Taking a far-forward look at commercial power prices, it is worth considering the demand effects of government legislation. These became more apparent last month, with Whitehall confirming measures to phase out all domestic gas use, starting with new-build homes after 2024, on top of government targets set for electric vehicles. The numbers are still being crunched as we speak. However, our initial calculations suggest that to meet current Whitehall targets for domestic gas reduction and electric vehicle uptake by 2030, new supply volumes of 40 TWh/y and 160 TWh/y will be required, which could increase existing national demand to 520 TWh/y compared its 320 TWh/y level today.
In fact, any demand figure above 500 Terra Watt hours would look challenging given the current grid and generation constraints ahead. With all of the UK’s existing nuclear power stations bar Sizewell due to be retired well before then, it will be interesting to see how the government, grid companies and generators may work together to square this circle, without some shift in energy policy or without causing some consternation in the Forward Markets.
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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