Despite short-term pain, the EU’s liberalised gas markets have brought long-term financial gains

Today’s record-high natural gas prices have raised questions about the liberalisation of the European Union’s natural gas market and its gradual move towards allowing real-time market trading to set prices rather than long-term contracts.

While liberalisation has meant greater European exposure to the recent spikes in the price of imported gas, it has also cut the EU’s gas bills over the past decade. And the increased flexibility it provides will be essential as the continent transitions to greater reliance on renewable energy sources, which are cleaner but whose output is more variable.

Before the 2000s, most natural gas prices in the EU were determined by long-term contracts linked to the price of oil, a system known as oil-indexation. Gas prices followed oil price trends, with volatility smoothed by the use of moving averages. This provided a relatively stable reference price that underpinned large-scale investments in upstream projects, transport pipelines and liquefied natural gas (LNG) terminals. However, gas prices did not reflect supply-demand fundamentals of the gas market itself, and buyers in the EU were unable to take advantage of periods of lower-cost supply, particularly following the US shale gas revolution. Over the last decade, gas prices in the EU have gradually moved away from oil-indexation toward “gas-on-gas” competition, where prices reflect multiple sellers and buyers of natural gas on spot markets. The Title Transfer Facility (TTF) in the Netherlands emerged as the most liquid hub and relevant price benchmark in the EU, offering trading and hedging options to a growing pool of market participants.

Over the past decade, the EU also built up significant capacity to import gas via pipelines or as LNG. The shift towards spot market pricing allowed the EU to benefit from low prices for LNG imports during periods of ample supply. However, for reasons set out in a previous commentary, gas supplies are now tight and spot prices in Europe are at record highs. We estimate that EU countries will pay around $30 billion more for natural gas in 2021 than if they had stuck with oil-indexation. However, in aggregate, the gradual transition to gas-on-gas competition – which increased as a share of total gas imports from 30% in 2010 to over 80% in 2020 – has saved an estimated $70 billion in lower gas import bills cumulatively over the past decade. 

Today’s high prices are a reflection of gas’s value as a flexible energy source able to meet both short-term and seasonal peaks in demand. Falling output in the EU (particularly from the Groningen gas field in the Netherlands) and in the United Kingdom has diminished capacity to meet such peaks from domestic production. The last large-scale use of domestic capabilities to meet sharp swings in demand was in 2015-16. Since then, imports – in combination with storage injection and withdrawal – have largely filled the gap. 

Looking ahead, in the Stated Policies Scenario of the World Energy Outlook 2021, which reflects how the energy system could develop based on today’s policy settings, EU gas demand declines by around 10 billion cubic metres (bcm) between 2020 and 2030. But domestic gas production falls at a faster rate over the same period, declining by 15 bcm to a level 30% lower than in 2020. As a result, LNG and pipeline imports grow to meet the supply gap. Over the same period, gas imports by emerging and developing economies in Asia rise by 250 bcm, setting the stage for greater competition for marginal volumes should periods of tight supply arise again.

In the World Energy Outlook 2021’s Announced Pledges Scenario – which assumes the EU’s net zero emissions targets are achieved in full – energy efficiency improvements and the expansion of technologies such as heat pumps and batteries mean that natural gas demand falls by 20%, or almost 90 bcm, by 2030. In this case, EU gas imports peak in the mid-2020s.

The dilemma for policy makers is that, despite declining overall demand, flexible gas supply remains essential over the next decade, particularly in the power sector. Detailed hourly power modelling shows that, even though gas use for power generation on an annual basis is 10% lower in 2030 relative to 2020, peak weekly demand is 15% higher. This is because gas-fired power generation plays a much greater role in helping to balance variable renewable sources of generation such as solar and wind.

Moreover, even as heat pumps replace direct natural gas use in buildings, the seasonality would be transferred to the electricity sector, where gas-fired power would again be the fall-back option. Under today’s system of marginal cost pricing, gas import prices would still exert considerable influence on the affordability of energy during periods of peak demand.

As the IEA emphasised in its recent statement on natural gas and electricity markets, the links between electricity and gas markets are not going to go away anytime soon: as clean energy transitions advance on a path towards net zero emissions, global natural gas demand will start to decline. But it will remain an important component of electricity security, and a parallel ramp up in low-carbon gases such as hydrogen and biomethane, and a reconfiguration and repurposing of gas infrastructure, can ensure that gases continue to play an essential role in managing large seasonal variations in electricity demand.