The recent rally in the TTF Oct-19 contract means it is now trading above the 5% fuel switch trigger. This contrasts with the prompt, which is still trading below the parity switching trigger. The fundamentals, outside of the risk of a significant reduction in French nuclear capacity availability, still indicate prices will need to drop to encourage full coal-to-gas fuel switching next month for the market to balance. Northwest Europe will also need pipeline supply to ease y/y. The loose supply-demand balance is due to strong incremental LNG supply and the likelihood that there will be almost no storage capacity left to make October injections. However, Oct-19 prices are likely to maintain their risk premium until there is more clarity on whether the technical French nuclear issues reported by EDF will result in shutdowns that could boost French gas demand.
We expect Northwest continental Europe to enter October with storage at maximum capacity, leaving no meaningful injection capacity and contrasting with injections of 3 bcm in October 2018. That demand drop will only be partially offset by a 0.33 bcm uptick in LDZ demand if we assume a return to seasonally normal weather, given that October 2018 was very mild. That leaves an additional 2.7 bcm y/y of demand that would need to be realised in the region’s power sector, or a supply turndown. If Oct-19 prices move to fuel switch parity trigger—where a gas plant is in merit over a coal-fired unit with the same efficiency (currently at 11.81 €/MWh)—that would absorb 0.6 bcm of the surplus, leaving 2.4 bcm to be balanced by lower supply.
Lower Dutch production will help partially tighten the balance, given that a lower Groningen cap could take roughly 0.5 bcm of supply out of the market next month. This assumes the proposed 11.8 bcm production cut will come into effect (see E-mail alert: Proposal to drop 2019-20 Groningen production by 6.1 bcm y/y likely to be unachievable, 10 September 2019). This assumes the proposed 11.8 bcm is agreed to by Parliament. Still, there will be considerable pressure on Norwegian and Russian supply to drop, given that aggregate LNG supply into Europe looks set to remain strong at 2.5 bcm higher y/y (+40%). In order to cut Norwegian flows y/y, Equinor would likely need to turn down Troll output substantially, owing to incremental supply from new fields. We expect supply from new fields (Aasta Hansteen, Johan Sverdrup, and Alfa Sentral) to add around 20 mcm/d to Norwegian supply next month, which would mean cutting Troll output to roughly 93 mcm/d—the lowest for the month since October 2013—just to make Norwegian production flat y/y. Prices will have to be low to get Russian flows to turn down, even if the decision by the EU court on OPAL results in a 1.5 bcm of Gazprom flows out of that pipe y/y in
October (see E-mail alert: Court ruling on Opal dents winter balances by up to 9.0 bcm, upping ante on securing Ukraine transit agreement, 10 September 2019). Gazprom could replace all of that gas with flows via Ukraine given spare capacity at Velke Kapusany and could still facilitate OPAL flows by selling more gas at the Griefswald beach via the ESP. Gazprom has ways to work around some of the new physical constraints, so it may need to be an economic incentive that drives a turn-down in Russian supply.
|Fig 1: Norwegian production, y/y, bcm||Fig 2: Potentially affected French nuclear units|
|Source: NPD, Energy Aspects||Source: Various, Energy Aspects|
French flashback to 2016?
Despite the very loose-supply demand balance, the Oct-19 contract will likely continue to hold some of its current risk premium until there is more clarity on whether the French nuclear plant abnormalities reported last week will result in shutdowns (see E-mail alert: EDF announcement on nuclear plant anomalies raises spectre of high winter outages, supporting markets, 11 September 2019). We think that there are 5 plants (11 units) with a combined installed capacity of 14.4 GW that could be at risk of a shutdown. A 14.4 GW loss in nuclear capacity would reduce French nuclear generation by about 10 TWh/m. If all of that loss was offset by gas-fired generation, it would add 2.0 bcm/m of demand y/y. A 2.0 bcm/m rise in French power sector gas demand next month would balance the market without a turndown in supply. However, gas will still have to price competitively against coal for all of the lost nuclear generation to be replaced with gas-fired generation, rather than a mix of gas- and coal-fired generation.
For 10 TWh of nuclear generation to disappear, that would require the French regulator ASN to both take a quick decision and require EDF to take rapid action regarding all of the affected nuclear plants. As such, while an abrupt shutdown is the scenario of maximum impact, it is just as possible that we see a more gradual approach to dealing with the discovered abnormalities and actual shutdowns could be much more limited over the coming winter. Few or no nuclear shutdowns would require more gas burn in the power sector or a supply turn-down in pipes—and both of those will require flat TTF prices around the parity fuel switch trigger.