Can the EU reach its ambitious new targets to cut reliance on Russian gas while maintaining energy security?

Diane Elijah


LONDON (ICIS)–The EU has unveiled ambitious plans to reduce reliance on Russian gas by two-thirds by the end of this year, using measures tabled by the European Commission.

The focus will be on:

  • Increasing non-Russian gas supplies
  • Optimising storage
  • Reducing demand for gas

The new strategy tabled on 8 March is called the REPowerEU energy communication

With the measures outlined, the equivalent of around 64 billion cubic metres (bcm) of Russian gas could be replaced by the end of the year, the paper says. This would be replaced by more non-Russian LNG and pipeline imports and by boosting biomethane production. This could then increase to 103-128bcm by the end of the decade.

The EU could import 50bcm more LNG from Qatar, the US, Egypt and West Africa, and 10bcm more pipeline gas from Azerbaijan, Algeria and Norway in 2022, the commission said in its paper, confirming to ICIS that this was in comparison to the previous year.

ICIS analysis has found that the pipeline target, much like the LNG target, is potentially impractical.

Piped dreams – by ICIS European gas analyst Thomas Rodgers

The Russian gas and oil industry, including exporter Gazprom, have largely swerved direct sanctions from Europe – an acknowledgement of how critical they are to security of supply for the continent.

A commitment to import an additional 50bcm of LNG is, while possible, not assured and impractical.

The EU also claims another 10bcm can be found among Europe’s other pipeline suppliers – namely Norway, Algeria and Azerbaijan.

Part of this additional volume – which the EU is measuring against 2021 imports – has already been accounted for by suppliers delivering all they can to high-priced European markets.

Additional upside to reach that 10bcm figure in 2022 is, much like the LNG target, impractical.

There is also the arguably more significant issue of Russian contractual limits putting a floor on imports considerably above the EU reduction goal.


State-owned Equinor, responsible to marketing the majority of Norway’s gas to Europe, in September 2021 received permits from the government to increase supply from two field fields from October that year. At the same time Equinor shifted to prioritise gas exports in their hydrocarbon portfolio, sending volumes to Europe that had previously been used for reinjections to improve oil recovery.

The Norwegian Petroleum Directorate (NPD), Norway’s offshore regular forecasts Norwegian gas production for 2022 at 117bcm, already 2bcm higher than in 2021.

Anymore increases above the already elevated rate are going to be hard to come by, with little more flex to come from upstream fields.

In theory, Norway could deliver over 127bcm to Europe if the recent maximum flow rate was extrapolated over the entire year. This however would require no planned maintenance and unplanned outages, which could have operational consequences for upstream assets.


Algeria is Europe’s third largest piped supplier, with routes to Italy and Spain delivering 35bcm in 2021.

There is scope for increase, if a diplomatic spat between Algeria and Morocco can be resolved, but that would only bring lows up from their lower base. Any scope for further increases is unlikely to be realised in time to materially impact supply in 2022.

Algeria stopped supplying Spain via the MEG pipeline which transits Morocco in November 2021, compensating the lost volume only partially via higher flows via the Medgaz pipe which goes straight to Spain. Algeria has backfilled the lost 0.5bcm/year via LNG, so a resolution of the dispute could bring additional piped supply to the market and free up those LNG cargoes to head to other parts of the continent.

Any increased supply to Spain would have a reduced impact to the continental balance due to limited interconnection to the wider European market. In a scenario in which Spain is already taking a long of LNG cargoes, there would be fierce competition to export to France along just one pipeline.

Italy is the other key landing point for Algerian volumes. Exports via the Transmed pipeline hit a 10-year high in 2021, totalling 21.1bcm – below the 34bcm/year capacity in the pipe.

Italian buyers optimise imports around oil-linked long-term contracts, with offtake reducing in the summer. Monthly flows hit a maximum rate of 2bcm/year in 2021, if a gas price premium were to be in place imports could ramp up to 24bcm over the year.

Further increase are unlikely as they would need additional long-term contracts and assume there are no upstream constraints in Algeria.

Nearby Libya delivered 3.2bcm to Italy in 2021. However, the ongoing humanitarian crisis in the North African state has severely damaged the gas industry which will continue to cap supply to Europe.


Azerbaijan became Europe’s newest supplier in 2020 when the TAP pipeline project was completed, the end of a large network which brings gas from the Shah Deniz development to European markets.

Flows via the 10bcm/year pipe, the vast majority underpinned by long-term contracts, and are already on track to reach that limit in 2022. Exports totalled 8.4bcm in 2021.

TAP’s capacity can be doubled by boosting compression capabilities along the pipeline, but this increase will not come online in 2022 and will take years. A market test is due to end on 18 March, but negotiations over new long-term contracts for the extra capacity will take time, before considering the physical work to build the compression stations.


Even if Europe were able to achieve all of its supply diversification and demand destruction goals, they would still face the problem of Gazprom’s contractual limits which place a floor on exports to Europe.

With Gazprom retreating from the spot market, all but a tiny fraction of its flows to Europe are underpinned by numerous take-or-pay contracts with a number of utilities. These carry a degree of flexibility which buyers are able to optimise around but typically have a lower limit, any volumes buyers chose to nominate below this is still charged for.

According to database of Gazprom contracts collated ICIS, this floor sits around 110bcm for 2022.

A reduction in deliveries below a contractual floor, without paying, would be a breach of contract – one which Gazprom would be minded to take to arbitration. Buyers would need to claim force majeure, a clause that essentially frees both parties from liability of obligation when an extraordinary event or circumstance beyond the control of the parties, to offtake below that level without paying.

While there will be such clauses for war, none of the contracts deliver into Ukraine – something a seller would likely bring up in any arbitration case.

Fact Check: Can the EU import 50bcm more LNG? By ICIS global LNG editor Ed Cox

LONDON (ICIS)–The EU has said Europe could import 50 billion cubic metres – about 36m tonnes – more LNG in 2022 than the previous year.

On paper this is possible, but it is not practical.

To reach this kind of figure will require more import infrastructure and more firm LNG supply commitments – not something the EU has backed in recent years.

It would imply total European LNG imports of around 104m tonnes in 2022, based on Europe’s imports of 67.6m tonnes in 2021, according to ICIS LNG Edge.

This would be a huge all-time high.

European LNG import capacity sits at 156.3mtpa.

But much of the most well-connected capacity is already running at high rates with little scope for additional imports.

Spare capacity is generally in markets that are less well connected to key demand centres.

The European Commission said it would look into whether investment was needed to overcome bottlenecks limiting the use of LNG.

The most obvious issue is the limited pipeline gas capacity between Spain and France.

Spain has almost 45mtpa of LNG import capacity, the most in Europe.

Terminal utilisation is also below the European average, according to ICIS LNG Edge.

But any major rise in LNG to Spain would currently provide little benefit to the rest of Europe unless it was reloaded and delivered as LNG to other terminals.

It is also notable that the UK is no longer a member state of the EU and as such would not be signing any new laws, or in a position to veto them.

UK LNG imports were 19% of Europe’s total in 2021 and it provides a key location for Qatari supply.


It appears the EU may have studied recent January and February LNG import totals and extrapolated a figure for 2022 based on these sums.

January and February were the highest two months ever for European LNG imports, with a combined total of 16.6m tonnes.

March LNG imports again look strong but will not come close to January’s record, when sources reported challenges obtaining slots to bring cargoes into several terminals.

Why then the fall in March from January when European prices are so high?

For one, Asian LNG demand is holding up late into the winter.

Qatari LNG exports to Europe are also lagging March 2021 levels at present.

Qatar saw four new term LNG contracts start up in early 2022, three for delivery into China and one into Taiwan.

This should be a reminder to the EU that a significant chunk of LNG to Europe comes when demand and/or contractual obligations fall in other parts of the world, especially in Asia.

Qatar is the second largest supplier of LNG to Europe after the US and has a range of contracts with European buyers.

But Qatar also sells significant LNG volumes to Europe on a flexible basis. If Asian contract demand rises, then Qatari LNG to Europe may fall.

Likewise, if Asian spot LNG prices are higher than Europe then a portion of US LNG – currently Europe’s largest supplier – will not come to Europe.

In January, European price signals secured record LNG imports – a sign the market was working effectively.

But this was secured at extremely high prices.

The EU may continue discussions with global LNG sellers and buyers but its influence falls well below supply and demand fundamentals, price signals, and global seller-buyer commitments.

LNG in Europe has not been baseload supply for much of its history.

It sat alongside the more dominant – and often cheaper – pipeline gas supply.

The situation is different in countries such as Japan and South Korea which do not have alternate gas supply options and depend on LNG for gas supply.

These countries will go through periods of lower demand but when they require gas they will ramp up LNG imports, regardless of any urgent requirement Europe may have for LNG.

The pool of potential LNG suppliers to Europe is limited.

Would the EU advocate European buyers signing large, firm LNG contracts with US developers?

This is one way that new supply could be guaranteed – in a few years, albeit at a cost.

Or even for European buyers to compete more directly with East and South Asian buyers for LNG expansion volumes from Qatar?

Otherwise LNG supply to Europe will continue to bounce up and down each month and fall way short of the Commission’s target.

Storage, demand and hydrogen – By Gretchen Ransow, Jake Stones and Diane Elijah

LONDON (ICIS)–By April, the commission will present a legislative proposal requiring underground gas storage across the EU to be filled up to at least 90% of its capacity by 1 October each year. Until this proposal is submitted and approved by the European Parliament and Council, member states should act as if it was already in place, the REPowerEU paper said.

As of March 2022, 13 member states have storage obligations in place.

As an incentive to refill storage the commission will propose increasing the rebate on transmission tariffs to storage to 100% from the current 50%.

ICIS estimates that if shippers withdraw at the March withdrawal rate of 2017-22 for the rest of the month, commercial storage sites across the EU27 will be just under 16% full on 31 March, holding 15bcm of gas.

As a result, shippers would need to inject around 72bcm during the gas summer to reach the threshold of 90% full by 30 September, or around 395mcm/day.

These figures include Gazprom-operated EU storage sites, and the volume of injections needed mean Gazprom’s sites cannot remain empty if the level is to be met.

The REPowerEU paper underlined that not all member states have underground storage facilities and so, if new interconnectors between member states are needed, they should be hydrogen compatible.

In the commission’s future legislative proposal on storage, EU energy regulators will have to certify that ownership of EU storage facilities by persons from a third country does not jeopardize the bloc’s security of supply.

Russia’s state-controlled producer Gazprom has storage facilities in Germany, Austria, the Netherlands and the Czech Republic with combined storage capacity of nearly 14bcm.

Concerns regarding Gazprom’s strategy for its EU-based storage arose when, in late October, these facilities held just 3.9bcm of gas compared with an average 12.7bcm the same time of year in 2017-20. These facilities were also below the EU average of non-Gazprom-owned storage and remain so today.


Boosting energy efficiency, further electrifying the energy grid, and higher or earlier targets for renewable energy are among the measures proposed in the REPowerEU paper to help bring down gas consumption.

Further measures to cut the equivalent of 38bcm of gas by the end of the year were also outlined in the REPowerEU paper. These were:

  • Reducing heating in buildings
  • Accelerating the roll-out of heat pumps to replace gas-fired heating in households,
  • Additional wind, solar and renewable hydrogen


The commission also outlined substantial revisions to renewable hydrogen targets by 2030.

Renewable hydrogen is produced using an electrolyser that is powered with renewable power. This means renewable hydrogen is produced and used without producing carbon emissions.

As outlined in the Fit for 55 package in July 2021, the commission targeted the use of 5.6 million tonnes (mt) of renewable hydrogen by 2030. Such hydrogen would displace 9-18.5bcm of natural gas.

But under the communication paper that target was revised up substantially to 20mt of renewable hydrogen by 2030. The increase of around 15mt of renewable hydrogen is split between imports at 10mt, and domestic production of 5mt.

Alongside this, the commission noted the importance of other zero-carbon production methods, with a focus on nuclear hydrogen. This is a slight shift in rhetoric from national hydrogen plans released to date, including the commission’s hydrogen strategy, which have largely focused solely on the production of renewable or low-carbon hydrogen. The exception to this point is the French hydrogen plan, which outlined the introduction of zero-carbon hydrogen, with later policy discussions showing a clear leaning towards nuclear power for hydrogen production.

The 20mt target is expected to reduce gas demand by around 25-50bcm by 2030. This figure is included in the overall target of cutting Russian gas supplies by 103-128bcm.

To support the growth of renewable hydrogen, the commission is aiming to develop a regulatory framework to support the hydrogen market’s growth. Further, the commission aims to support the development of hydrogen infrastructure, such as storage sites and port infrastructure.

Market participants have noted that hydrogen storage will be crucial for the renewable hydrogen market. This is because it supports production of renewable hydrogen as a balancing mechanism for when solar and wind power generation exceeds demand.


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