GIF Inside Story: Regulation and LNG contracts drive European storage disparity

LONDON (ICIS)–On the morning of 28 July 2021 the British NBP front-month jumped to trade at a new 16-year high, the second time it had done so that month.

Later that day the same contract on the ICIS benchmark Dutch TTF would close at an all-time high, again for the second time in a month.

Unless a number of factors shift the balance, there is every chance that Europe’s benchmark markets will continue to set records through the rest of the summer and into winter.

The key driver has and will continue to be sluggish restocking rates that has left European storage at its lowest point for the time of year in at least seven years.

As European buyers are failing to compete with Asian buyers for LNG, hub prices are rising in order to bring coal power plants back in the money and relieve some of the strain on the gas market.

Uneven distribution

However, the sizeable deficit is not one that is uniform across the continent, rather one that is mainly being felt at markets where gas storage is almost or entirely liberalised – no obligations as to why shippers must use capacity or quotas to meet ahead of winter.

In Germany and the Netherlands, the two largest storage markets by capacity, stocks are down by 50% compared to the same time last year. In smaller markets where storage legislation is also light like the Czech Republic and Austria, volumes in store are down 48% and 55% respectively.

Capacity holders in these hubs have felt the brunt of the global squeeze in the market, with injection buyers consistently being outbid by global and local competitors.

In Italy and France, Europe’s third and fourth largest storage areas, policy makers have decided to not leave it up to the market to meet peak winter demand. Shippers are under obligations to either inject or withdraw certain amounts over a month of have an obligation to have a certain amount of gas available for withdrawal by winter.

Regulatory arbitrage

French regulation dictates domestic stores must be 85% full by 1 November.

The potential costs incurred by imposing requirements on the market has been softened by a compensation regime that makes French storage capacity some of the cheapest available through auction in northwest Europe.

In December 2017, French energy regulator CRE introduced a compensation mechanism for storage operators, with the aim to ensure security of the supply and keep costs stable for end users. The mechanism involves both auctioning storage capacities and covering the operators’ costs if they exceed the revenues from the auction process.

In June of this year the European Commission ruled that the mechanism complied with laws on state aid. One of the reasons the Commission said the regulation did not distort competition with other member states was that the auctions were open all gas suppliers. Although France will continue to monitor this impact until 2024 at least.

So while the regulation and prices means French storage often fills up first, the gas does not have to meet domestic consumption when its withdrawn.

In Italy, significantly stricter rules have dictated minimum injection requirements over the summer. While some flexibility has crept into the Italian storage market over the past few years, the regulations has meant shippers are incentivised to pay for high-cost gas supply in order to avoid more expensive penalties.

LNG opening

This requirement to fill up stores means both markets have had to attract what little LNG is available to Europe.

While market like Britain have seen LNG sendout plummet from rates in excess of 70 million cubic metres (mcm)/day April to less than 10mcm/day in July, French output has fallen at a shallower rate – from 82mcm/day to 37mcm/day.

The majority of cargoes coming to Britain come from Qatar, but with no firm commitment the volumes only flow to the NBP when they cannot find a higher price elsewhere. Other mid-term contracts to other sellers in the US and elsewhere are also flexible.

French Total has brought in the majority of cargoes to France over the summer, with the minimum storage requirement and failing pipeline supply offering a strong incentive to bring LNG into its domestic market. The supermajor sourced the majority of the cargoes through its various long-term contracts with a portion bought on the spot market, according to LNG Edge.

In Italy, most LNG arrives at the Adriatic terminal under a contract between utility Edison and Qatargas which does not carry the same flexibility it may otherwise in Britain or the Netherlands. Importers could pay to cancel cargoes but it is unlikely to eclipse any fees for not meeting Italian storage quotes.

Winter price formation

Storages are filled to meet demand in the winter when it outstrips the import capacity of the network.

Yet despite the discrepancies in stock levels between the major European markets, spreads in the first quarter contract – that carries most of the winter risk – have been relatively resilient.

The NBP Q1 ’22 premium over the TTF has hovered between €2.00-2.50/MWh through the summer. The British market has significantly smaller storage capacity relative to demand compared to its mainland European neighbours and typically has trade a premium to attract imports.

The Italian PSV premium flipped from a premium to a discount earlier in the summer but has again re-established a premium in July, despite Italian shippers injecting at faster rates than their counterparts in Germany and the Netherlands. The French PEG discount meanwhile has held steady through the summer.

While French storage sites have to meet fullness quotas by November, there is no such obligation that the stored gas has to go towards meeting French demand. The strong interconnection, where a lot of capacity is still under long-term contract means gas can flow at a relatively low cost to neighbouring markets. So the bearish impact of French stocks only goes to soften the bullish drive of lower stocks elsewhere.

France’s exposure to the relatively isolated Spanish market also carries a degree of winter risk.

The Italian premium is also in part due to the regime which caps withdrawals when market forces may want them to go higher. In these situations the hub has to call on spot imports from the north at a relatively high price. Although the likelihood of this has reduced with the start of the TAP pipeline delivering Azeri gas to Italy.

These geographic spreads, while stable for now, may blow out in the short-term market when high demand puts a strain on transport networks struggling to push gas to where demand is.

While different regulation and market design will continue to drive differences in storage outcomes across Europe. Physical interconnectivity and low barriers to trade ultimately means the task of meeting winter demand is one the continent must tackle together.