Impact of Groningen cap on European natural gas markets flexibility

July 2015 | Anders Norlen, Rembrandt Sutorius


Upstream flexibility has been declining in the North West European1 natural gas markets since the turn of the century. The recent decision by the Dutch government to further limit the Groningen natural gas fields’ production will only accelerate this process. Storage facilities in the region and Russian exports to the region will stand to gain.

The seasonal production swing2 has been declining rapidly in North West Europe over the last 15 years as existing natural gas fields have been maturing. While the United Kingdom and Germany still provided 35-40% of the region’s seasonal flexibility needs in 2000 (5.0 and 1.1 bcm/month of production swing respectively), by the end of 2014 that swing capacity was virtually exhausted. In the same period, Norway increased swing capacity from 1.9 to 3.1 bcm/month, but Dutch swing capacity dropped from 7.3 to 5 bcm/month.

In addition to the overall decline in swing production in North West Europe, the region’s largest and most competitive source of seasonal flexibility – the Groningen natural gas field – is now also losing its swing capacity. Recent earthquakes have prompted the Dutch government to reduce output from the Groningen natural gas field in the first half of 2015 to 16.5 bcm and by an additional 3 bcm in June 2015 to 13.5 bcm in the second half of 2015. This is just enough to ensure security of supply but stands at almost half of the 25.1 bcm produced in the first half of 2014 and, therefore, severely limits the field’s ability to play its historical role of swing supplier, requiring other seasonal supply sources to step up.

The decision on further reducing Groningen natural gas production in the context of the region’s overall decline in production swing capacity has resulted in some major questions in the market: Where will the supply of seasonal flexibility come from in the future? Are there sufficient alternatives to ensure security of supply? Will the market experience increased seasonal price patterns? In this article, we aim to address some of these questions.


Exhibit 1


How will seasonal supply be met in the future?

There are several options to replace declining production swing capacity in the region. The market can use seasonal storage, leverage volume flexibility in piped supply contracts from Russia or Norway, and/or import increased volumes of LNG in winter. We believe that the market will likely use storage and piped imports from Russia for its supply of seasonal flexibility, as Norwegian swing is exhausted and LNG will be too expensive during winter months.

1. Norwegian swing capacity exhausted

Swing capacity in Norway is largely limited to the Troll field, which supplied 29 bcm in 2014. The field has a production capacity of 120 mmcm/day (3.6 bcm/month), a capacity which is normally fully utilized in the peak months to supply the UK market. Natural pressure drop has forced the operator to install additional compressor capacity to maintain this production capacity, but it is unlikely that production capacity will increase in the future.

Another limiting Norway’s potential to provide additional seasonal flexibility to the North West European market is the fact that export pipeline capacity (11.4 bcm/month) is unlikely to increase and renegotiation of contracts indicates that Norway will fully use current capacity with increasingly base load deliveries. Low season exports to North West Europe increased by 1 bcm/month as growing market liquidity has enabled Norwegian upstream players to use storage facilities closer to end users and reduce flexibility in long-term contracts.

2. LNG seasonal supply flexibility expensive

High LNG prices in winter make LNG imports an unattractive source of supply flexibility. Asian LNG imports are highly seasonal and peak demand in Asia coincides with peak demand in North West Europe. A lack of extensive storage capacity and alternative supplies has made East Asia heavily dependent on seasonal imports, forcing buyers in this region to bid up spot volumes in times of seasonal peaks in demand, thus making Asia a more attractive market than Europe in the winter months.

Nonetheless, with low utilization of LNG regasification capacity of only 18% in 2014, a loose LNG market until 2020 with current spot prices at all-time lows, and European-Asian summer price spreads relatively narrow, LNG is likely to play a role in supplying seasonal storage in summer.


Exhibit 2


3. Russian supply flexibility available and competitive

Russian supply flexibility is likely to increase its role in the North West European gas market. The Nord Stream pipeline, connecting Vyborg in Russia with Greifswald in Germany, has been operating far below its monthly operational capacity of 4.6 bcm/month, but is still expected to see additional capacity being added in the future3 . The low cost of Russian production flexibility, combined with the low opportunity costs for increases in Russian imports with excess pipeline capacity, will lead to Russia trying to capture a larger part of seasonal supplies.

Direct import capacity to Germany from Russia through the Nord Stream and Yamal pipelines currently amount to 55 bcm/year and 33 bcm/year, respectively. Physical flows from Russia amounted to 64 bcm in 2014, leaving over 20 bcm of annual pipeline capacity non-utilized. We believe that Russia has the ability to ramp up its production for increased winter deliveries, as it has proven this in the past. This should allow for increases in direct imports from Russia on both an annual and seasonal basis, probably increasing Russia’s role as peak demand supplier to above the 20% it provided in 2014.

Additionally, storage operators and other customers will likely increase overall imports from Russia to cover for the overall decline in domestic production. These volumes will be increasingly important for summer injection into storage, but also for direct imports in winter months. We estimate these imports to grow by 8-10 bcm/year by 2020, with half arriving in the winter months.

4. Seasonal storage able to play a bigger role

Significant seasonal storage capacity has been added over the last few years, following an increased push for security of supply and an anticipation of a reduction in seasonal supply from domestic upstream sources and correspondingly higher winter/summer spreads. The total seasonal storage capacity is expected to reach 34 bcm by 2025 up from 25 bcm in 2015, with a total withdrawal capacity of 0.33 bcm/day. In reality, this will provide 3-8 bcm/month of bridging over the peak demand months. In addition to the seasonal storage facilities, there is 24 bcm of flexible 4 storage, with a withdrawal capacity of 0.66 bcm/day.

Over the last year, storage utilization has been increasing as a response to production caps in Dutch upstream production. Inventories hit an all-time high in November 2014 at 27.1 bcm, touching the ceiling for capacity. Withdrawals accelerated in early 2015 to much higher levels than for 2014, at 0.23 bcm/day for the winter 2014-15, compared to 0.09 bcm/d for the winter 2013-14. This development - although not revolutionary - is an example of what to expect in the future when increased storage liquidation in winter months and higher summer injection levels will be the new norm.

Conclusions

The decline in seasonal swing capacity from North West European domestic upstream sources will be met by a combination of increased direct swing supply from Russia and increased seasonal storage capacity. Imports from Norway and LNG suppliers are unlikely to provide significant flexibility but will be instrumental in providing gas to be injected into storage facilities during months of low demand. Calling the ultimate mix of these different sources is hard as they depend on a wide range of different factors such as regulation around storage facilities, geopolitics, Russian pricing strategies, global LNG market balances, and weather effects

The shifting tide from seasonal supply from domestic upstream to imported sources has come more swiftly than previously forecast. Part of this shock will be absorbed by structurally lower demand to 2020 than previously forecast, mainly driven by lower gas-to-power demand across the region. North West Europe will have to adapt to a situation in which it has increased dependency on importers who will act opportunistically to capture the value this change will bring.

1Germany, the Netherlands, Belgium and the United Kingdom
2Defined as difference between low-season (April-September) and peak-month production (December-February)
3Announcement in June 2015 by Nord Stream to double capacity of system
4Short cycle storage facilities (aquifers, salt caverns)

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About the authors

Anders Nolen is a Senior Analyst in Energy Insights' London office,
Rembrandt Sutorius s General Manager - Gas in Energy Insights' Amsterdam office.