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    Weekly Overview: What Price Flexible Gas?



Last year was a bad one for GasTerra, formerly Gasunie – the big player in the peak gas supply market for millions of homes for many decades in northwest Europe

by: William Powell

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Weekly Overview: What Price Flexible Gas?

Last year was a bad one for GasTerra, formerly Gasunie – the big player in the peak gas supply market for millions of homes for many decades in northwest Europe – and its shareholders, which include the Dutch state itself.

The revenues from gas sales are falling on a per-unit basis; and so are the volumes from Groningen, the cornerstone of its business, thanks to the Dutch state which decided to act to limit production before it did any more structural damage to houses built near the field. GasTerra buys all the output and markets it at home and abroad – including the UK, whose dominant utility Centrica took 8bn m³/yr – as a once-premium product.

But the fate of Groningen is instructive. Gasterra's CEO, bemoaning the fate of the field, said: “Business will never be the same again,” announcing poor financial results.

Groningen gas was typically the most expensive of all the gas sold in Europe on oil-indexed contracts because the buyer could vary the offtake at very short notice. Storage capacity was still needed to inject Norwegian and Russian gas in summer, as these supplies met the bulk of the region’s demand on an annual basis.

But Groningen was top of the range, producing little in the summer relative to the winter when it filled in the gaps in supply as the temperatures dropped or disappearing when they rose. The Centrica contract which expires this year was a good example: it took five eighths of the annual volume in the six months of winter, the other three eighths in the summer.

Now with industrial demand down across Europe, power-stations belting out particulates from coal – Phase 3 carbon emissions are still trading around the €5/metric ton, around a tenth of where the price would need to be to encourage meaningful switching to cleaner fuels – and subsidised renewable energy eating away at the margins, storage across Europe is full of long-term gas that has lost its market. Even the weather is not co-operating.

The average daily demand in the UK in January and February was hovering at 300mn m³, two-thirds of the peak send out that the grid is capable of.

Storage still plentiful

As the last month of winter begins, there are still 38bn m³ of gas stored away across the European Union in depleted gas fields, aquifers or hollowed-out salt caverns. That is, on average, they are 41% full. Beyond the EU, even Ukraine, which does get properly cold winters and whose relatively low inventories tend to cause tremors of alarm each September, is still at a third of capacity, having started the season not much above half full. Ukraine went into the last two winters – the two for which data are available on Gas Storage Europe website – with around 17bn m³ to see it through the months ahead.

This generally depressed atmosphere in the storage business finds further expression in National Grid’s decision in February 2015 to shut the last of its five LNG peak-shaving sites: Avonmouth. By no means on a par with the reduction of output at Groningen, and with reliability problems and its old age also counting against it, it is nevertheless symptomatic of the times we live in.

These LNG sites were always the most expensive storage sites, as gas had to be purchased for liquefaction and stored, with boil-off an inevitable consequence. They were also typically in network sensitive areas – so far away from the beach terminals that interruptible contracts were an important tool for balancing the gas network.

Price signals discourage building

The summer-winter spread in prices in the UK – the first EU market to discard the predictability of oil-indexed, demand-agnostic gas prices in favour of the market – used to be wide enough to justify building and using storage, even of LNG. It only needed to be vaporised on a handful of very-high-priced days to pay for itself as there was so little of it and there were anyway licence obligations to supply households, come what may. But the sites were no longer economic. Following last year’s consultation with the industry, National Grid will drain it before closing it at the end of next month.

Long-term storage is still essential for domestic suppliers for insurance purposes; and the fast-cycle salt caverns may still be handy for traders to make money in short-term arbitrage. But at present it would be risky to build it without store-or-pay agreements underpinning the investment, and the growing number of LNG import terminals, often funded by the taxpayer, ultimately – are themselves LNG storage sites as well as delivery mechanisms into the grid.

Flexibility is not as valuable as it once was, and neither are gas markets. That perhaps explains the very few mentions of storage in the European Commission’s strategy for LNG and Storage, which the European Union Commissioner for Energy Union Maros Sevcovic presented at an NGE event March 2 in Brussels.


William Powell