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    European gas storage in a global market [Gas in Transition]


April was a shoulder month like almost no other: a collision of many factors, outside Europe’s control, could leave the continent under-stocked by the next heating season. [Gas in Transition, Volume 1, Issue 2]

by: William Powell

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Natural Gas & LNG News, Europe, Top Stories, Insights, Premium, Gas In Transition Articles, Vol 1, Issue 2

European gas storage in a global market [Gas in Transition]

Withdrawals from Europe’s gas storage facilities were continuing well into May, more than a month after the injection period would have started in a typical year. This has raised questions about the continent’s state of readiness for next winter and the prospect of higher prices for delivery after October.

Storage facilities exist because the alternative – major pipelines capable of carrying the customers’ peak day demand – would be uneconomic. Gas flows at a steady rate over the year and in the days of European gas monopolies, it was injected into storage facilities at times of low demand.

In a competitive world, by contrast, the “invisible hand” of the market is meant to take care of storage by responding to summer-winter price signals. But this year there is no price signal: summer prices are almost the same as winter prices. There is no incentive now to inject.

There were three major reasons for the slow start on both the supply and demand side. First, it had been a very cold April, meaning gas was needed for heating for longer. Second, other sources of power generation such as wind, hydro and French nuclear power, were all low, making gas more necessary in the power sector too. And third, carbon prices were also high, reaching and even exceeding €50/metric ton in early May. The continuing bull run provided a reason to burn gas instead of coal where possible.

There were another three reasons on the supply side: lower than expected deliveries from Russia; maintenance offshore Norway, which will see less gas produced as essential maintenance work was held from last year by COVID-19; and US LNG, which might have been expected to come to Europe, went instead to capture the higher netbacks from Asia as it was cold there too.

More predictable is the fact that the Dutch Groningen gas field is no longer allowed to provide the swing service that it used to. This means that another source of peak gas supply is less.

It is true that Gazprom could have booked more short-term capacity through Ukraine as it did last year, at a cost; but it has chosen not to exceed the pre-arranged volume so far this year. Had Gazprom been allowed to complete Nord Stream 2 on time, it would by now be carrying more gas than the annual capacity deal with Ukraine allows: 55bn m³/yr compared with the 45bn m³ booked for this year.

All these factors explain the relatively small quantity of gas in store: 340 TWh as of May 8, which is where it had been a month earlier.

Uniper Storage – the fourth largest operator in Europe and Germany’s largest, with facilities also in the UK and Austria totalling 7.5bn m³ – told NGW early May that the low inventory level was all the more remarkable since facilities in Germany had been 94% full at the start of the winter but were now down to 30% full, at best.

Uniper Storage head Doug Waters said that storage had again “proved its worth” this winter; it met 61% of German gas demand in January, he said. Overall, storage had supplied 717 TWh last winter and it was still meeting demand in May, he said. During the particularly cold snap mid-month, it was also enabling gas to meet peak electricity demand in the UK for example, as there was almost no wind generation.

“There is no alternative to storage for physical gas supply,” he said. The surest alternative to storage is LNG and the market had mistakenly assumed that more LNG would arrive than was the case: in the event, he said LNG deliveries to Europe were down about 45% year on year.

And yet now Europe faces the so-called “storage paradox,” he said. Typically, market appetite for storage injections is reflected by the summer-winter price difference but at the moment, that has almost vanished.

There is no commercial benefit in buying gas now as the winter price is only €1/MWh higher. That difference has to cover the shippers’ pipeline exit/entry capacity costs as well as the storage operators' margin. In order to attract injections, the difference between summer and winter has to widen, meaning winter 2021-2022 prices could rise at the major gas hubs.

“Low storage levels at the end of the heating season result in higher injection demand from storage sites; this further tightens the market through the summer; which in turn drives up summer gas prices more quickly than the winter contracts and hence reduces summer-winter spreads,” the company explained. Waters said someone was going to be on the wrong side of this: storage would struggle to get above 80-90% full, he said, unless winter prices rise – or summer prices fall.

Commenting on the situation, consultancy Timera Energy said in a May 10 research note that: “curve backwardation in commodity markets (when forward prices are discounted against prompt delivery) is often bullish. It may be the back of the Dutch TTF forward curve that will be dragged up by higher near-term prices as 2021 progresses.”

Some of Uniper’s storage facilities straddle national borders: Etzel is on the Germany-Netherlands border and the Austrian facility 7Fields, which is technically operated by RAG but whose capacity Uniper markets, also allows traders to access the German market. It sells capacity on either a fixed (for one-year contracts) or indexed basis, where the price varies with the summer-winter price difference. On those contracts the volume is locked in but the price is not known until the average spread has been calculated each year. In common with other operators, it sells capacity both as bundled units, where space comes with injection and withdrawal; and as separate units, allowing owners to trade between themselves on the secondary markets.

UK: problems ahead

Storage capacity, as a proportion of annual demand, ranges widely across Europe. Most countries have built storage capacity using depleted gas fields (long-range storage) or developed them from salt caverns (short-range storage) or aquifers. But the UK, which had been a gas exporter until almost 20 years ago, relied on swing production from the Morecambe Bay fields and the depleted and now unavailable Rough gas field to meet peak demand.

With the closure of Centrica’s Rough facility in 2017 for financial reasons, the UK now only has 2% of its supply covered by storage, compared with about a quarter elsewhere in Europe. Demand for peak gas is often synchronised in northwest Europe as the weather tends to be the same across the region. So the UK is having to bid against others for the molecules.

This makes the UK vulnerable, according to Clive Moffatt founder of the UK Energy Security Group. He toldNGW: “Natural gas is critical in what will be a slow transition to net-zero and whether it be to secure supplies of power or heat or a possible source of hydrogen, more UK gas storage is essential.

“We are vulnerable on physical supply and price security now and we will continue to be so because, despite the popular tide of liberal opinion, we are going to be dependent on gas domestic boilers. Hydrogen – be it blue or green – is, as the majors know, an economic non-starter; and heat pumps are simply too expensive and less effective in winter. And power generation – both for baseload to compensate for the lack of coal and nuclear and for peakload to combat system imbalance caused by more wind – will be necessary for many more years. And with our almost total reliance on imports after 2025 we need more storage. We cannot depend on pipes and LNG to be there when needed.”

The UK government and the energy regulator Ofgem, ever since the closure of Rough, have said that the market, not taxpayers, should decide whether to take the risk of an investment in new storage facilities. And those that have the potential for conversion, such as the all-but-depleted Saltfleetby gas field in Lancashire, might be used for storing other gases altogether.

It is a complicated argument: for some governments, strategic stocks are a straightforward matter of controlling prices and responsibly ensuring supply; but nobody will invest in new capacity if there is the chance of government intervention that will make the asset worthless. Turn on the taps, and the investment loses its value. And in a theoretically single market, the actions of one operator will affect more than one country.

Refilling: an imperative

Replenishing storage is an “imperative for this year,” Giacomo Masato and Evangeline Cookson, analysts at brokerage Marex, told NGW in an interview late April. They drew comparisons with the last time the European injection season had got off to such a low start, which was 2018, and said injection demand had been the most important factor behind the high gas price.

This was an unusually cold April and this has meant that the customary rebound, with injections starting at the end of March, did not happen: in fact, facilities went from 30% full to 29% full in late April, before gaining a little afterwards.

The comparison with 2018 suggests worse is to come, because although European storage ended with less gas in store that winter, facilities were already filling up again during April. They said: “We had gone from 18% full at the end of March to 23% full by late April.

“It was the 2018 ‘Beast from the East that led to a rapid withdrawal from European facilities at the end of the winter. The step-change came later on, from a large wave of LNG from the US and this lowered prices during the following winter.”

They continued: “This year, stocks had been 12% higher at the end of March relative to March 2018 but now [late April] we are only 6% higher than three years ago. Prices were pulled higher during that restocking phase and rose to $27-28/MWh.

“This is potentially worrying as 2018 ended with EU stocks at 85% full as the withdrawal season was about to start. That is a tight supply for the beginning of the forthcoming winter and the market is aware that a repeat of 2018 is possible.” The October 2020 season began with storage about 93% full.

“April can deliver significant withdrawal, but injections cannot wait any longer than the start of May, so then injections have to happen, whatever the price. That is why now the price curve is flat from now until December in Europe: summer trading has eroded the summer-winter spread. If storage reaches only 85%-90% full by October, that will send a bullish signal. But if it goes above 90% full, the market will happily wait to see what demand does,” they said.

There are some grounds – based on the current Asia-Europe spread from June onward – for believing that the LNG send-out over Europe may well decline during the second half of the restocking phase. And if Russia had booked incremental capacity through Ukraine – and it had been expected to do so, they said, judging from the brief drop in EU gas prices in late April – then that could lower Dutch TTF prices, making storage more attractive. But at the same time it would push more LNG into Asia, and away from Europe. The lower Europe’s prices become, the less attractive a destination it is for LNG relative to Asia.

The Asian-EU premium for prompt delivery of spot – as opposed to long-term contracted – cargoes was about $1/mn Btu in late April. “We have noticed that when the difference between the two is well below $0.50/mn Btu then the LNG will primarily target Europe. But at $1/mn Btu or more, Asia becomes much more competitive and can erode parts of the global supply share away from Europe.” However, a week later the premium was down to $0.4/mn Btu, suggesting that a turnaround in Europe’s fortunes is coming.

As to the longer term, there are reasons the global market could redistribute LNG more evenly.

“US facilities are now at their highest levels of output but there have been delays across the value chain owing to the COVID-19 pandemic, slowing down buildout. If Asian import expansion continues to grow faster than expansion from key exporters (such as US and Qatar, among others) we will see the competition for gas between Asia and Europe maintained and naturally, prices will rise,” they said.

But there is more optionality in Asia where power generation is concerned: gas is not the only fuel and there is no carbon market. Japan is bringing back more nuclear plants into service and coal is still widely burned. “All forms of diversification will be taken into account there, while in Europe the soaring price of carbon works against coal and in favour of gas,” they said.

China has been upping the use of facilities that can use LNG and its expansion has been very rapid as it moves away from coal. Even building LNG import facilities gives it mini-LNG storage, the analysts say, which in turn fractionally eases the pressure on demand.