Energy Highlights Q4’23: Oil, Geo-political Developments and Electricity

Our Energy Economist, Dominic Whittome shares his Energy Highlights Report on oil, natural gas and electricity prices at the start of 2023. Delving into the dynamics of oil, natural gas, and electricity prices, this marks the commencement of a comprehensive 3-part blog series.

Oil prices clip $97 amid Saudi-Russian brinkmanship

The crude market has seen a near-uninterrupted three-month rally; Brent witnessing its largest biggest quarterly jump since the 24th February 2022 invasion of Ukraine.

Spot prices have ticked back but traders continue to eye $100/bl amid worsening output constraints reported across Middle Eastern producers, notably North Africa; Russia’s decision to extend its 300,000 barrel a day cut until the end of January which – in all probability – it will extend or expand; and Saudi Arabia’s poker-faced silence in respect of relaxing its own production cuts which have served as the principal catalyst here.

Geo-political developments to unsettle commodities further

Separately, Russia has since suspended all exports of diesel fuel which now looks set to drive up European prices of middle-distillates even further, notably jet-kerosene and heating oil as blenders & distributors complete their winter stocking.

As discussed earlier, Russia has had an economic incentive to steer oil prices higher, even at the expense of its own export revenue, if only to fan the flames of inflation in European countries and so chip away at their support for sanctions and assistance generally for Ukraine. Also discussed last issue was the Balkans. There are now new and unsettling reports of Serbian ground troops amassing on the border with Kosovo. A contingent of British troops has since been rushed to the region this week to support the NATO contingent which was mobilised just days ago. How this plays out and to what extent the Russia-Belarus-Serbia alliance expands is anyone’s guess. But to some it is clear Russia is starting to play its geo-political card and energy weapon in unison. Destabilising the region now could pay Russia four dividends: first up, a serious fare up would divert military hardware resources and divide political opinion over continued aid to Ukraine in Europe and the USA; it would stretch NATO’s own military resources further; it would reinforce historic military alliances with principal former Warsaw Pact countries; and finally it could paradoxically make the West more reliant on Russia assistance in ‘broking’ a ceasefire were war to break out, triggering a major new  refugee crisis which could soon be spilling across central and western Europe. The heightened tensions in the region can only unsettle energy commodities markets further and this should be one consideration for major energy buyers or “Beware the Balkans…” to quote Winston Churchill himself.

Base-load electricity prices drift down, but uncertainty remains on the horizon

Base-load power prices continue correlating closely with gas prices, as they have this year so far and all of last year. The Forward Year contract fell back 15% last quarter thanks to weak space heating & industrial demand, softer gas prices, an especially weak coal market (down from over $320/tonne to £120/tonne in just eleven months), replenished cooling-water levels and, above all, a high reactor re-commissioning programme by EDF over the summer.

Additionally, the electricity trading arena has recently had the benefit of forward price forecasts released by National Grid as well as by some well-respected other energy consultancy firms. Each one has painted a generally stable forward picture, if anything with base-load prices softening further, with most of the forward curve exhibiting backwardation in years extending out past 2030.

The current fundamentals for electricity might look encouraging now. However, here again, there is a ‘contrarian’ view to be made.

Because the objective at least is for UK electricity demand to double in order to decarbonise the gas grid by 2030.

It is doubtful that this goal will be achieved, especially in light of recent announcements relating to Net Zero target slippage. However, whatever form of new government we see come the end of next year, Net Zero targets remain intact. And during this critical period to final gas decarbonisation, be it 2030 or 2035, the UK will be evermore dependent not only on solar & wind (which both blow hot & cold reliability wise) but also increasingly dependent on inter-connectors. This can actually ‘double up’ the security of supply risk in some instances because not only might the power supply be renewable and not necessarily guarantee contractually either, there is also reliability of extended seabed cables to contend with. For, even using state-of-the-art technology, these import wires are known to be problematic, even if supply is resumed after several days each time.

A snapshot of the current and future systems linking the UK grid to other countries is given below. It reveals that up to 20% of the UK’s marginal electricity supply could be supplied by overseas’ generators based on current peak demand.

2023 Total Volume (import only) 7.4 MW  

2023 Peak Demand Call                  59.9 GW

2030 Total Volume (Maximum)    18.8 GW

2030 Peak Demand Call  (est.)     90.0 GW

The capacity to foster inter-connector imports and renewable power through energy storage

Even if hoped-for investment in electric storage, which may be commercially feasible, does go ahead, the UK system does look like it will be increasing prone to sporadic outages over the years ahead. For it is unlikely that extra peak-load generation and large grid-scale batteries (be they lithium-ion, redox-flow or another chemistry) combined will be enough to keep the UK’s high-voltage transmission and distribution grids stable throughout the year. Or not as things look, with investment expenditure concerns adding to the reliability and intermittency questions outlined above.

One recent report, by The Royal Society, considers the cost of grid-scale energy storage. It concluded that almost 100 TWh (one hundred trillion Watt hours) of capacity will be needed to keep the grid balanced by 2050, based on accepted Net Zero projections concerning changes in national load-shape and annual electricity demand.

To put that in perspective, 100 TWh is over 1,000 times the current storage the UK has installed including existing hydro-pumped storage facilities. In terms of capital investment costs, if we take the accepted industry norm of, say, $95/kWh which is ca. £80/kWh, then the nominal cost involved for the UK of any extra 100 TWh would work out at  

100 trillion Watt hours which is 100 billion kilo Watt hours = 100,000,000,000 kWh, which @£80/kWh suggests the extra 100 TWh would, if it was ever installed, cost the economy £8,000,000,000,000 (eight trillion) over the target Net Zero horizon discussed in the report.

So nothing close to this 100 TWh storage requirement figure can be afforded. Of course, there are economies-of-scale to consider. But $95/kWh is already a wholesale market price for stationary lithium-ion storage. Grid -storage costs are not falling either, or not to the extent that some pundits had expected. There is a developing shortage of the rare earth metals needed. Additionally there may further storage-specific grid reinforcement costs to be added, some of which the Royal Society’s report did not to cover.

Battery storage will have a crucial role to play, especially as new interconnectors come on-line and additional load-balancing & contingency supply is required for indigenous renewable energy as well. However, sheer scale of capital investment costs, production, project development and grid-connection lead times all round mean that electricity storage can only play limited roles at any one stage of the Net Zero transition.

Consequently it does look like ‘something has to ‘give’. Options are limited but policy improvements could include government promotion of peak-load ‘clean coal’ power station; development of bio-gas, hydrogen and modular reactors (but all three of these do involve significant & understated problems and are not necessarily recommended); government regulatory support to resuscitate the ‘Behind-the-Meter’ (BTM) battery market (a once virile, infant UK industry which was last year by Ofgem’s Targeted Charging Review (TCR) and changes to triad pricing at the bequest of the electricity distribution monopolies; extended regulatory support for grid-scale storage developers; doubling-down on demand-side response & related energy efficiency programmes; but these are just some.

Read the second and third parts of this series to further explore the intricate dynamics of the energy landscape.

Part 2:

Part 3:

Dominic Whittome

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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