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LNG demand: buyers’ strategies in Europe, 2020 - 2030

Posted by on 26 June 2019
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This article is the concluding piece in a three-part series assessing the evolution of the LNG market over the next decade. The first two pieces can be found here.

Read on as independent LNG consultant Guy Broggi considers Europe’s typical role as an LNG market of last resort, and what this may mean for buyers’ strategies going forward.

120 – 150 Mtpa of additional LNG supply are expected to enter the market by 2024. Which of the world’s LNG consumers will absorb it?

Europe currently represents around 25% of total LNG imports. Often viewed as “the LNG sink” in case of market oversupply, Europe is a remarkable place to do business for energy suppliers thanks to its size and its ability to pay.

It’s no surprise that the competition between Qatar, Russia and the US for their share of LNG markets has not been limited to North-East Asia, but has become serious with respect to Europe as well.

Although it is the world’s largest supplier, Australia is a bit too far away to fully compete within the European market. However, this has not prevented Australian energy company Woodside selling LNG to the main German Gas & Power utilities, RWE and Uniper.

Woodside have also committed to future offtake agreements from the US to serve European LNG players – proof that the LNG market is becoming truly internationalised.

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Europe at a glance

Despite the goal of an always-more-integrated EU energy market, most energy policy decisions are still currently in the hands of national governments, whose goals may not always be perfectly aligned.

There is also Brexit to consider, which will one way or another will affect the way natural gas is traded within the current EU member states.

Geopolitics are playing an increasingly significant role, and LNG has to remain economical against strong headwinds. Competition with coal may have been won easily within the power generation sector (except for in Germany and Poland), but pipeline natural gas can still limit the penetration of LNG into the energy mix.

This energy mix will also have to become less carbon intensive to ensure compatibility with the Paris Climate Change Accords, which is driving a sense of urgency within the industry.

As always, price is of the essence in the end for any commodity. But when it comes to the related infrastructure, security of supply tends to trump costs, which will be paid for by a multitude of end-users anyway. How could a new nuclear investment in the UK be otherwise explained?

The domestic gas fields depletion in the North-Sea and in Groningen, added to uncertainty about the long-term deliverability of gas from Northern Africa, has already led to the building of LNG terminals in Western Europe and Turkey.

These will permit a balance of supply from sources scattered all over the world, including potential LNG from the East-Mediterranean region at some point down the line.

For similar reasons, Germany has become the latest EU country to wake-up to domestic LNG imports, with plans to develop genuine German LNG terminals on German territory.

Excluding Turkey – which deserves special attention – Europe is made up of the 27 EU member states, plus Norway and Switzerland, who are associated members.

To this can be added the Balkan countries, who are potential future members of an economic block and are already linked by pipelines to other EU member states, and finally Ukraine and Belarus, both subject to the EU Commission’s attention regarding their gas imports.

As far as LNG is concerned, it is possible for Ukraine to contemplate importing LNG from terminals located on the Black Sea coast.

The same would be more difficult for Belarus, unless they negotiated swap arrangements with other LNG players (as Switzerland has been doing for years with French players to have indirect access to Nigerian LNG.)

Let’s turn to the individual LNG players to assess who will be the major importers in the years to come, and in what quantities.

The first thing to consider is which players have booked capacity at European LNG terminals and could be potential off-loaders (buyers) of extra LNG.

The LNG suppliers

In the traditional LNG market, buyers used to commit LNG on destination restricted long-term contracts and were responsible for their terminal regasification capacity.

However, extra LNG available from sellers’ plants needed to find a home somewhere. This led sellers to book capacity at terminals in advance – a tendency which will not soon cease.

Algeria’s NOC, Sonatrach

Sonatrach has been contracting capacity at National Grid’s Grain LNG terminal, which allows it to market natural gas within the UK.

But Sonatrach has mainly been selling LNG at destination through their long-term contracts and is said to be looking at a joint venture with a trading company to help them diversify their list of customers.

The future export policy of Sonatrach will be easier to assess once the current political situation reaches a stable outcome.

Qatar’s LNG producers

Before the Fukushima disaster and the US shale gas revolution, the marketing doctrine of Qatar’s LNG producers was a “one-third” share for the each of the three basic areas of LNG consumption: Asia, Europe and the Americas.

The recent IGU report demonstrates that in 2018, this was no longer the case. Asia received 74% of exports, Europe 21%, and the Middle East 3%, with the remainder heading to South America. There were no cargoes imported by the US.

Left over from this former vision, however, is the idle Golden Pass LNG import terminal in the US, which is set to be turned into a liquefaction facility (the project took FID in February, with Qatar Petroleum taking a 70% share).

Also left over are several arrangements with European terminal capacity owners when contracting LNG buyers had surplus capacity to be offered on an optional basis (a put-option).

These include the Qatargas-II project between QP, ExxonMobil and Total, developed alongside the South-Hook LNG terminal at Milford Haven in South Wales.

Total contributed to the project through contractual arrangements using the French Fos Cavaou LNG terminal for its committed quantities.

In Italy, Qatar Petroleum and ExxonMobil have developed the 6.5 Bcma Adriatic LNG terminal near Rovigo along with the Italian utility Edison.

On top of that, Qatargas has been signing LNG contracts with capacity owners at the Gate LNG terminal in Rotterdam and the Zeebrugge LNG terminal in Belgium. Put-options have been negotiated to allow the seller to use this capacity as needed.

Russia’s Yamal LNG partners

The Yamal LNG project has been negotiating ship-to-ship transfer slots at the Zeebrugge LNG terminal. This allows for the use of Arctic-7 LNG tankers for a limited voyage before the LNG is loaded onto standard tankers.

Total’s quantities from the project will be directed to the French terminal facilities at Dunkirk or Montoir-de-Bretagne.

But before the start date of the long-term contract, each partner has access to LNG (an equity portion) which can be sold through other facilities like Gate LNG terminal in Rotterdam or Grain LNG in the UK.

The transfer facility does not indicate where the molecules will be eventually consumed and therefore cannot be defined as demand creation.

Russia’s Gazprom

A small increase of global LNG demand might come from Gazprom’s newly installed Marshal Vasilevskiy FSRU facility in the Russian enclave of Kaliningrad, competing directly with pipeline gas which crosses EU territory in Lithuania.

Gas and Power Utilities

Within the EU, the current penetration of LNG into the energy mix can be gauged by assessing its share of natural gas consumption, with pipeline gas as its main competitor.

The absolute consumption of natural gas in Europe is generally forecast to remain constant in future. Ultimately, this will depend on each country’s response to the energy transition.

The “replacement of coal” policy may well work in France, Spain and Germany (although it will likely find some resistance in Poland), but nobody can say for sure that natural gas will be the only winner.

Portugal (regas capacity: 6 Bcma)

In 2018 LNG represented 69% of total gas consumption in Portugal, although terminal capacity usage was still only 51%. This should leave some headroom for an increase of LNG usage before displacing other fuels.

Spain (regas capacity: 44 Bcma)

Spain has been a pioneer in building new LNG terminals. This move has served to lessen its dependence from Algeria, the country’s main supplier of pipeline gas.

Long-term contracts were installed in the 1990’s with Nigeria and Qatar. More recent contracts have been signed with Norway and Russia, who now have access to the Spanish market, which would otherwise be difficult to reach via pipeline.

As a result, 48% of natural gas consumption came from LNG with a regasification utilisation rate of only 25%. This leaves some margin to absorb some of the LNG expected to hit the market in the 2020’s.

The recent acquisition of Iberdrola’s LNG business by Singapore Pavillon Energy is another proof that European gas market can attract LNG sellers from abroad.

On the bunkering side, Spain has been developing facilities for the usage of LNG as a bunker fuel, and this activity could stimulate sustainable demand, although at a low level.

Even with a sound renewable energy policy, the switch from coal to natural gas could lead to an absolute increase of gas consumption, to spur terminal utilisation.

Italy (regas capacity: 11 Bcma)

Well connected with pipelines from Russia, the North Sea and producers in the North Mediterranean, not to mention the Southern Gas Corridor, Italy is one of the least reliant European countries on liquefied natural gas. LNG makes up just 12% of its total gas consumption.

Three terminals are in operation, with a utilisation ratio of 56%. One is almost dedicated to Algeria (ENI with Sonatrach at Panagaglia LNG), while Adriatic LNG is an Edison-Qatar venture.

Edison has been contracting LNG from Mozambique and the US, while ENI might be willing to use its Damietta LNG contract in the future.

Whether or not Italy will build more regas capacity remains to be seen. The country can present problems in terms of local environmental reluctance to new building.

France (regas capacity: 25 Bcma)

A historical pioneer of LNG usage in the early 1960’s, along with the UK, France has developed the second most extensive assemblage of regasification infrastructure in the EU.

This is the case despite a power generation sector mainly based on nuclear energy since the first oil shock.

The country’s regasification capacity averages a 40% utilisation rate, allowing LNG to represent 31% of total gas consumption.

Therefore – should prices prove competitive enough – LNG still has room to penetrate the French gas market in the years to come.

French major Total’s integration of Engie’s LNG business also makes France a natural destination for LNG from Total’s growing portfolio.

UK (regas capacity: 36 Bcma)

Brexit complicates matters for LNG demand in the UK. The country’s natural gas infrastructure is intimately linked to the continent. LNG imported via UK terminals can be used to provide natural gas to North East Europe under current EU rules, and the UK can receive natural gas from the Continent.

Only 15% of regasification capacity was used in 2018, and LNG penetration in the UK reached only 9.5%. This leaves a tremendous potential for LNG absorption (and indeed, much higher utilisation rates were seen in the first half of this year).

After Brexit we could witness a huge increase in LNG imports to the UK, depending upon many variables, including differentials with continental market prices. Only the future will tell.

Belgium (regas capacity: 7 Bcma)

Home to the Zeebrugge LNG terminal – which is located near the landing point of the Interconnector pipeline, which links the UK with the continent – Belgium is also a transit country for natural gas from Norway to France.

24% of domestic consumption was covered by LNG with a 40% utilisation rate at Zeebrugge.

The Netherlands (regas capacity: 9 Bma)

Traditionally a gas hotspot, with formerly significant revenues from its giant Groningen gas field, the Netherlands may be very reluctant to bet on natural gas in the future.

LNG represented only 10% of its natural gas consumption, while the Gate LNG terminal in Rotterdam averaged a utilisation rate of 39%.

Capacity owners at Gate LNG – operated by Gasunie – are E.ON Global Commodities, EconGas (OMV’s German subsidiary), the Danish utility Orsted, RWE and the Dutch utility ENECO.

RWE agreed to sell part of its capacity to Shell (including for bunkering and trucking) while it is considering using a new terminal in Germany, promoted by a consortium including Gasunie and Vopak.

The recent bunkering operations by Shell’s inland barge LNG London will allow LNG bunkering in Dutch ports along inland channels.

Recent news from Gate LNG indicates that Gasunie is testing the interest of LNG players for more regas capacity to be added to the current 12 Bcma.

Greece (regas capacity: 5.3 Bcma)

Greece’s sole LNG terminal, Revithoussa LNG, has just been expanded with EU funding to be able to store 225,000 m³ of LNG.

Greece imported 0.73 Mton of LNG in 2018 according to the IGU, mainly from its long-term contract with Algeria’s Sonatrach, as well as one cargo from Qatar and one from the US.

The Greek domestic gas market is not of a sufficient scale to swallow a large influx of LNG. However, as an entry point to Southern Europe – and with the necessary construction of a link with Bulgaria – it could become an interesting alternative to the TurkStream pipeline.

Poland (regas capacity: 5 Bcma)

The first Polish LNG terminal at Swinoujscie was developed to provide an alternative to Russian gas. As a result, LNG is responsible for more than 20% of Polish gas imports, essentially coming from a founding Qatar LNG contract (2 Mtpa) and from Norwegian supply.

A 2018 US cargo was also bought as a precursor of a further long-term contract with Cheniere.

The future LNG trade in Poland consists of three new long-term contracts with US exporters for 7.0 Mtpa and a plan to upgrade the regas capacity to 7.5 Mtpa. These are all in place to enable the country to stop buying Russian pipeline gas when contracts terminate.

Lithuania (regas capacity: 4 Bcma)

The Lithuanian story of LNG has been discussed at length during the last five years at every European LNG conference. The Independence FSRU has been in operation since December 2014 at the Klaipeda harbour.

With a regas capacity of 2.2 Mtpa (4 Bcm) it received up to 1 Mton in 2016 and only 0.6 Mton in 2018 according to the IGU.

Well located along the Baltic coast, the Independence serves regional bunker markets as far away as Finland, and will find itself in competition with LNG from a liquefaction plant recently developed by Novatek, located in Vysotsk, Russia.

Finland (Pori, Tornio)

In Finland, two small-scale LNG receiving terminals at Pori and Tornio operated by Gasum are already serving the bunker market, as well as some demand from the domestic market after regasification.

The recent announcement of a new LNG import facility close to Riga in Latvia is a further indication that LNG has a bright future in the Baltic area.

Malta

A successful LNG-to-Power project has been running in Malta since January 2017, with SOCAR acting as the sole supplier. The FSRU Armada LNG – anchored at Delimara – is co-owned by SOCAR, SIEMENS and GEM Holdings. It received 0.26 and 0.45 Mton of LNG in 2017 and 2018 respectively according to IGU figures.

Gibraltar

Shell and its bunkering subsidiary Gasnor have just opened a small FSRU which will primarily serve the bunker market and provide natural gas to a gas-fired power plant on the territory.

Croatia (Krk island project)

After more than ten years on the drawing boards of several companies, the Krk LNG terminal in Croatia may see the light of day thanks to an EU financial push for a second entry point of LNG into the Adriatic region.

To make it a game changer in terms of supplying European gas demand, it will have to reach end-users as far away as Serbia, Hungary and even Austria (whom Gazprom are not ready to leave to competition without a struggle).

Germany (Several projects)

Both the big German utilities Uniper and RWE are supporting plans to build LNG import terminals at Wilhelmshaven (Q-Max FSRU) and Brunsbüttel respectively. These are expected to become operational in 2023, in time to receive LNG from their Canadian and US LNG commitments.

ExxonMobil and Shell, both producers who have been affected by the decline of Groningen production, are supporting their clients’ terminals by committing to long-term capacity agreements.

In addition to the German utilities, Switzerland-based Axpo entered into a capacity agreement with RWE’s German LNG terminal for future usage.

In terms of its potential absorption of LNG, Germany could be a game changer in the current energy environment.

Conclusions

According to the IGU, Europe averaged a utilisation rate of 33% for its 165 Bcma of regas capacity in 2018. This leaves a potential 110 Bcma of additional capacity to attract further imports of LNG, without counting the expansion of existing projects or the development of new import terminals.

This would represent an increase of 85 Mtpa of LNG demand out of 120-150 Mtpa of supply increase expected by 2024 – far larger than Europe’s 25% total market share today.

However, Europe’s energy future is still uncertain for the following reasons:

  • Brexit has not yet been delivered. Nothing can be clearly anticipated about the energy relationships between the UK and the EU, or the EU and the US.
  • The Ukraine stalemate after the de-facto invasion of Crimea by Russia has yet to be resolved, and discussions between Gazprom (Russia) and Naftogas (Ukraine) will have to be concluded by year-end. This needs to happen before the fate of gas transit through Ukraine can be assured for European customers of Gazprom, as the current transportation contract between Russia and Ukraine is set to terminate by 2020.
  • The commercial imbalance between the US and the major European economies could lead to an increase in US LNG imports at a time when public sentiment in the EU does not tend towards valuing natural gas as a sustainable fuel for the future.
  • Because public sentiment in Europe concerning the fossil fuel usage does not bode well for an increase in natural gas demand in the future, the fate of future imports of LNG is strongly linked to the desirability of pipeline imports and the power struggle between Russia and the US.

To summarise, pure economics will not be the key factor. The fate of new liquefaction facilities in Europe to absorb a share of the 150 Mtpa of extra LNG supply will be strongly influenced by geopolitics, including the US China trade war and the relationship between Germany and Russia.

Supply-demand analysis has some value, but in the end the spot price level will determine whether there is too much LNG on the market or which buyer will have to pay a premium in case of scarcity.

Receiving infrastructure has historically been built and paid for by long-term reservation contracts, while producing facilities rely on financing from deep-pocketed sponsors and by lenders reassured by long-term take-or-pay contracts from sustainable utility buyers.

The current status quo is of higher utilisation of liquefaction plants than regasification terminals, which should provide some confidence that every molecule produced will find a home on the physical market.

It is worth noting that a new trend is however emerging. Suppliers feel ready to commit to financing terminals to be sure that potential demand can materialise, at least for their own quantities.

The current race from sellers around the world to liquefy as much otherwise stranded gas as possible – from Alaska to Papua New Guinea, and from the Russian Arctic to Argentina – will surely result in an increasingly global market for LNG.

A potential downward trend on spot prices could lead the way to a disconnect between crude oil prices and natural gas prices, which would benefit consumers both in Asia and Europe.

The jury is still out on whether this general price decrease will be enough to stimulate extra demand in more price sensitive markets.

The race for energy dominance is on!

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