French nuclear power availability will again dominate the agenda this winter and act as a driving force for both power and gas prices in France and across Europe. Traders are fearful of a repeat of last year, when outages sent shockwaves through the market and contributed to power and gas prices spiking to unprecedented highs.
Any contagion will likely spread to the Belgian power and gas markets, although the Belgian gas grid will also be strained by the prospect of record exports to Britain.
As France in January this year suffered the most serious supply crunch recorded in recent history, traders recently have been swifter to price in the risk of short supply on the near end of the forward curve compared to last year.
This is because an ongoing audit of French incumbent EDF’s nuclear components, initiated by nuclear safety authority ASN in August, has left traders wary of decisions that could lead to extended outages.
By the end of September, the French Q4 ’17 Baseload electricity contract expired at €55.35/MWh or €5.25/MWh above its Q4 ’16 contract last year, despite higher nuclear availability.
Previously mothballed gas-fired plants in France are now expecting a blossoming return to the market and should be able to operate both during baseload and peakload hours to make up for the shortfall of nuclear.
A repetition of unprecedented spot prices is unlikely. Experienced traders in the market expect power incumbent EDF to “surprise” the market in November/December by ramping up nuclear plants extensively.
This could start to exert pressure on Q1 ’18, although traders are unlikely to sell off contracts and go short.
Strikingly, the imminent uncertainty factor is ASN, which recently forced EDF to close temporarily three out of four 915MW units at the Tricastin nuclear power plant.
All eyes will therefore be on ASN announcements this winter.
In the event of low nuclear supply paired with cold spells, French spot prices have the potential to decouple from fundamentals, allowing speculators to take over the market by propping up prices.
Should Germany experience extended days with subdued wind and solar generation, which it did the previous winter, this could also limit cheaper renewable power to cushion spiralling French prices.
France’s combined-cycle gas plants in the south of France may play an important role for power prices this winter. They are among the last gas-fired power plants in the merit order and could therefore set the price during many hours. Gas prices in the south of France rely on sufficient LNG supply, which is more expensive that pipeline gas. A lack of LNG to France is therefore bullish for French power.
Nuclear concerns, low levels of gas in store, as well as stiff competition for LNG cargoes could drive substantial price volatility in France this winter. The main risk is likely to be felt in the more poorly-connected southern France.
Traders are fearful of a repeat of winter 2016/17, which saw the TRS Day-ahead and Front-month contracts spike to unprecedented highs. In January, the TRS Day-ahead’s premium over the PEG Nord equivalent jumped as high as €19.10/MWh.
A period of freezing temperatures, lack of LNG supply and an inability to deliver enough gas to south-eastern France via pipelines and storage sites, were the main drivers behind the spikes.
French authorities are working on reinforcing the grid to boost pipeline flows to the vulnerable southeast, but construction work will not be completed until winter 2018/19. The energy regulator has granted grid operators additional powers to keep the system running smoothly this winter, while the energy ministry has called on operator GRTgaz to build up additional stocks in the southeast to help mitigate the supply risk. But these measures will not be enough to solve the underlying structural issues.
Any fresh downgrades to France’s winter nuclear availability schedule will further tighten the fundamental picture, as gas-fired generation will be called on to fill the electricity generation gap.
This risk was reflected in the TRS Winter ’17 contract’s premium over PEG Nord, which soared from €1.20/MWh at the end of August to €2.05/MWh at expiry on 29 September.
In addition to low storage levels and nuclear concerns, this premium is reflective of a rising premium for month+1 and month +2 LNG delivery in Asia compared to southern Europe, which may act to draw in spot LNG cargoes otherwise destined for France and the Iberian peninsula.
In neighbouring Belgium, the absence of Britain’s largest storage facility, Rough, provides the main risk this winter. With Rough out of action, Britain will be more reliant on Belgian gas supply via the Interconnector pipeline than in previous years.
This will act as a drain on Belgian gas exports, which look likely to peak in the first quarter of 2018, based on price spreads at the end of the gas year.
The Zeebrugge-NBP Q1 ’18 basis was assessed at -2.625p/th on 29 September, an indication that high Interconnector flows are likely in early 2018. The pipeline has a maximum capacity of around 75 million cubic metres (mcm)/day in the Belgium-Britain direction. In the first quarter of 2017, the maximum recorded flow was 48mcm on 3 January, responding to a Day-ahead basis from the previous session of -2.60p/th. email@example.com and firstname.lastname@example.org