Having eclipsed the $70/bbl mark at one stage, the Brent contract fell back to finish the second quarter 8% down, as fears of an US-Iran war eased for at least for the time being. Nevertheless, the Persian Gulf remains a tinderbox, one which could cause crude oil prices, and petroleum product prices in particular, to snap upwards at some point. If recent history can tell us anything, perhaps it is that military campaigns in the Middle East can last longer and have far further-reaching consequences than initially imagined. So this latest stand-off with OPEC’s second highest oil producer in terms of proven reserves, could equally affect the forward markets for gas and electricity, not just prompt prices.
In this context, Gazprom of Russia and NIOC (National Iranian Oil Company) together hold some 80% of global gas reserves which are economically-recoverable at current prices. Although no Iranian gas to speak of is exported to Europe in significant volumes, certainly not yet, conflict with the US could have all sorts of impacts across energy commodities markets.
Leaving geo-political issues to one side, it may be worth looking at the supply & demand fundamentals. In particular, consensus industry estimates of the break-even (long-term marginal cost (LRMC)) of bringing new gas supplies to the European border over the next decade, as existing 25 year gas and LNG contracts (many signed in the late 1990s) expire.
One of many expressions bandied in trading circles is the one that “the market is well supplied”. By itself, this statement is perfectly true. The day-ahead market always clears after all. But it is not so much prompt market availability which affects wholesale or industrial gas prices. It is the ‘break-even cost’ (LMRC) of mobilising new gas supplies and bringing them to market.
The consensus industry estimates now put the LRMC for new gas supplies, those destined for North West Europe over 2020-2030, at between $8.00/MMBTU (for West African, Siberian and low-case North American shale) and $10.00/MMBTU (including Frontier LNG and high-case North American shale). Even were we to assume the lower-case eight dollar MMBTU figure and assume gas is delivered at or close to the break-even price (so no risk-premium and low supply margin), then at current exchange rates the UK wholesale gas price could still rise past 70 p/th, i.e. a third higher than today with the Annual Contract just closing the second quarter up 6% at 49 p/th.
So, notwithstanding Climate Change Emergencies and Zero Net Carbon 2050 targets set in Westminster, no demand side reduction or perceived ‘abundance’ will altar what the financials are suggesting: that gas prices may not fall far from here and even if they do it will not be for very long. No major producer will export at a loss. So, if our ‘cost plus’ valuation is accepted, then gas prices could start to rise as more legacy long-term contracts expire, replaced by higher-cost/ LMRC supplies.
For all its merits, renewable electricity does not offer reliable base-load supply. And it actually increases relative demand for peak-load generation. Given that all 14 operating reactors in the UK bar two at Sizewell will be decommissioned over the next ten years, today’s ca. 80 TWh demand call from gas-fired power stations looks very unlikely to fall. Indeed the share of gas in the UK’s generation mix may need to rise at some point. The combined domestic heating & industrial quotient for gas is much higher, at circa 250 TWh and there are measures to phase out use of gas in homes past 2025. However, this demand tail-off will be gradual. As the economics stand (and are unlikely to change) an impending deficit in flexible/peak-load electricity looks very plausible. Perhaps it can only be properly addressed by new forms of fossil generation, be it domestic gas-fired generation or brown- coal generation, imported from Poland or Germany through interconnectors. Either way, the consensus LMRC figures suggest in future, Forward Market gas prices will be higher.
Base-load power prices followed natural gas, rising 5% over this last period April to July. There was also the announcement that, for the first time in the UK’s industrial history, ‘clean electricity’ had exceeded fossil generation.
Amid the fanfare, it needs repeating that the Whitehall’s definition of clean electricity includes nuclear power. And while last month may have been a trailblazing one for renewables, the tail end of June saw day-ahead power prices spiking up to £375/MWh or 38 p/kWh. This was partly attributable to cloudy skies and low-wind speeds which severely cut renewable generation. More ominous perhaps (since such imports are being relied on more to fill any supply gap) was the wanting performance of Nordic and Northern Europe inter-connectors. The general reliability of such cables was discussed in recent editions of EH. In the event, it was domestic gas-fired generation that the system ultimately had to fall back upon on, come the day itself Monday 24th June.
This tale relates as much to nuclear power as it does to gas. The mainstream political parties remain opposed to any new-build gas programme and with no new-build nuclear reactors bar Hinckley on the horizon, the UK power market does appear to have a forward supply & demand picture that doesn’t stack up – or certainly the consensus in the Energy Highlight bunker just now. What this could mean is two fold. First, perhaps we should brace ourselves or hope for some change in government policy. Even it no change is announced any time soon and this can has been kicked many times before. Inter-connectors alone, even if/when the power supply is firm, will not compensate for GW output lost by retiring UK reactors. Second, it we assume there is no government money left for significant new subsidies and limited stomach either for new levies on households, then our energy authorities may well feel inclined to sit back, watch the market mechanism do its work and see wholesale power prices rise and so quell the energy demand to help the UK reach the new and somewhat fiercer ‘Zero Net Carbon’ emissions target announced last month.
Looking short term, power prices could rise if French, Benelux or German reactors shut due to lack of cooling water from reservoirs amid the European heat-wave. On the downside, renewables output is currently strong and across energy markets generally there are concerns over the global economy which may dampen both gas and electricity demand.
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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