In this article, Dominic Whittome covers recent changes to wholesale energy prices.
Oil fell 15% over the last two months to just over $50/bl. The Forward Market for crude generally has lost a third of its value since the end of last summer. Today there is little doubt that markets are still spooked by the indeterminate spread of Covid-19 and the prospect of a sustained shutdown which may cut medium-term consumption of petroleum products worldwide. Whilst a demand downturn is already very apparent in South East Asia at least, the longer term demand prospects are much less clear. On the supply side, the signals would otherwise be quite bullish for oil prices. Lost in the fog of recent coronavirus events, exports from major OPEC producers have faltered. The region’s security of supply situation looks set to remain fragile amid worsening civil turmoil and increased terrorist activity in several key oil exporting countries. Such unrest is thwarting desperately-needed export infrastructure redevelopment in OPEC states such as Iraq and is actually impending exports of oil itself in others; the total volume exported out of Libya during this January was zero for example.
With the world’s population set to grow 2 billion between now and 2035, much of it within the North African and Middle Eastern region itself (the population of Egypt alone surpassed 100 million in February) and with more of OPEC’s oil output set to be consumed internally, it might be a mistake to bank on oil prices re-establishing themselves at the current $50/bl for long in spite of ‘carbon neutral’ efforts said to be made in some western economies.
The Forward Year gas contract has now fallen some 40% since 1st January. Wholesale prices fell across the global market, hit by surplus LNG cargoes (unwanted by Asian buyers). Also European gas inventories are reported to remain stubbornly high just as we head into spring. Gas prices are actually now, in real terms, than they were after the UK gas market was liberalised in the early 1990s (under the infamous 90/10 Rule’ which obliged British Gas to sell 10% of its pre-contracted North Sea gas to establish the spot market we have today and below the Heren Index price in real terms, the bell-weather index as first reported in 1995.
However, there is no actual ‘security of supply’ concern in relation to gas. This commodity has an established and robust export network bringing long-term contract and spot supplies to Europe through well-maintained North Sea, Dutch, Russian, Algerian and LNG infrastructure routes. From a reserves perspective too, the gas supply outlook seems stable enough, with well over 250 years worth of forward supply cover, according to the reserves to production ratio published in the most recent BP 2019 Statistical Review. That said, unlike the case of oil whose reserves are held by various states and multi-nationals, over 75% of the world’s reserves of gas remain in the hands of two corporations: Gazprom Neft of Russia and NIOC of Iran. So looking long term, it will be important to consider both commodities through geo-political frames.
Base-load power prices continued sliding and the April Year 2020 contract fell another 25% to close at roughly £45/MWh. In real terms, power prices are only marginally higher now than they were in 1999 when the New Electricity Trading Arrangements (NETA) came into play. Most recently, the electricity price almost halved since the end-of-summer peak recorded on 1st October, 2019. But there has been no actual ‘step change’ in the UK supply or demand outlooks since then. There has been no positive news in respect of new-build gas or nuclear power stations. Both of which the UK must rely on, with all coal units now to come offline by 2023, one year sooner than originally planned. Sobering perhaps to recall in 1990 UK coal accounted for 71% of national power generation, compared with 2½% today. Question marks still remain over any commissioning date for the European Pressurised-water Reactor (EPR 1 design) at 3,200 MW Hinkley Point being built by investors EDF (56%), British Gas’s owner, Centrica (14%) and CNG of China (30%). No EPR1 has actually finished construction; the other two, in Finland and in France, have also been hit by delays. Hinkley’s investors secured a contract-for-difference (CFD) strike price (the CFD to be added to consumer bills) of circa £125/MWh in today’s money (under indexation terms for the headline £92.50/MWh Strike Price agreed in 2012). If we assume this new nuclear plant is commissioned and operates at 90% load, we can roughly predict the subsidy that will be added to domestic & business electricity bills over the 30 year CFD contract term. So the subsidy to be added to bills alone should amount to 0.9 x 3,200 MW x (£125 – £45) MWh x 24 x 365 x 30 = £60 billion circa in today’s money. This does imply rising power costs soon; also in the future considering the equivalent of 13 such-sized power stations will be needed to meet the UK’s expected 42 GW demand call by 2050. This one 3.2 GW nuclear plant will barely meet 7% of that quotient.
In January, the same consortium bar Centrica asked the government to underwrite a second, same design EPR1 reactor Sizewell under an alternative RAB model (regulated asset base) to entail direct Treasury support, though no decision has been made yet. Whilst the lead-time, capital risk and construction costs are far less for equivalent sized thermal power stations, the outlook for gas-fired plants has, if anything, deteriorated recently with reports of even the very smallest (sub 5MW) gas flexing units encountering local or (visiting) opposition from eco groups and no government lead as to the role that new build gas-fired stations should play. Looking forward therefore the UK power market currently looks stuck between a rock and a hard place. As pointed out in past editions of Energy Highlights, interconnectors and renewables will not come close to reliably meeting this 42 GW demand call in front of us. So in spite of regulator Ofgem’s current Targeted Charging Review, which will reduce ability of end users to reduce Capacity charges through triad avoidance, Demand Side Response should still have a role to play in helping businesses to cut costs, be it on-site generation, battery storage, heat recovery and energy conservation, as well as load-shifting itself. These options along with energy purchasing strategies could each help to mitigate contract price-rises ahead, especially if we see any snap-back in commodity prices as well. For the time being however, prices across the board look like staying subdued by Corona-virus related uncertainties.
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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