Andrei Belyi at the University of Eastern Finland says there are three main causes behind the huge rise in European gas prices. Everyone already understands that the reversal of the previous gas glut that gave us such low prices has been caused by a decline in European gas production, LNG imports and Russian gas deliveries. Added to that is the utilities’ reliance on spot contracts rather than termed contracts – great when prices were low – that means even though the gas exists it’s tied to rising prices. Finally, the rising carbon price at a time when inter-fuel competition (e.g. from intermittent and therefore unreliable wind and solar) is weak and cannot provide an alternative to fossil fuels. Belyi goes into the details and the numbers, as well as reviewing the politics (Russia, Nord Stream 2, Ukraine). He ends with his four conclusions: develop a pro-LNG strategy; reduce the over-reliance on spot contracts; improve information flows (i.e. supply, risks); pursue total system reliability to avoid shortages and ensure genuine inter-fuel competition.

Debates surrounding the new energy crisis are heating up as the spot gas price achieves new records. What could have gone wrong? Commodity markets are cyclic, therefore, supply volumes and storage capacity periodically change. High commodity prices are cured by increased competition, while low commodity prices are cured by a reduction in investment activities.

In normal market conditions characterised by inter-fuel and inter-company competition, gas price hikes would not have affected energy systems overall. Previous gas price hikes occurred between 2007 and 2008 as well as between 2011 and 2014, but without reaching the current record highs. Instead, since the commodity crisis of 2015-16, the world saw a glut in hydrocarbon markets. Since then, oil prices have stabilised due to OPEC+ agreements, while gas prices have experienced an almost persistent ‘low price season’. But market trends reversed, generating unprecedented pressure on energy systems.

Three major causes

This article will attempt to summarise three major causes of the crisis:

(i) the end of the gas glut caused by a decline in European gas production — in LNG (liquefied natural gas) deliveries and Russian gas deliveries

(ii) consumer reliance on spot as it used to be more competitive compared to termed contracts, and

(iii) weakened inter-fuel competition amplified by the rising carbon price.

LNG: Market changer

Over the last decade EU domestic gas production declined significantly, mainly because Europe’s largest gas field Groningen is on its pathway to being phased out. By 2020, the EU-27 import dependence is close to 85% which implies a need to ensure international market liquidity to retain competitiveness. Penetration of LNG to European markets would indeed fit this purpose. However, year-to-date (January-September) import dynamic reveals a decline in LNG imports by almost 25% between 2020 and 2021 (Fig 1).

Moreover, the most recent price hikes in Europe did not secure additional LNG inflows. Possibly, suppliers prefer markets with larger incremental growth in Asia and Latin America. Absence of LNG inflows further amplifies European worries of insufficient supplies. Utilisation rates of import terminals remained low compare to the last year, even though a slight increase occurred in September to reach last year’s lowest records (Fig 2).

Russian approach

The largest share of piped gas imports comes from Russia’s gas monopoly Gazprom. As Figure 1 illustrates, Russian volumes declined substantially in 2020 compared to 2019, but the year 2021 saw a slight increase compared to the level in 2020. Gazprom has been able to reduce the surplus in underground storage which dangerously persisted over summer 2020. The current level of underground storage capacity is slightly less than 70%, which allows ensuring supplies for long-term contracts but may leave utilities dependent solely on spot in deficit.

The Figure 3 indicates that Russian flows via Belarus and Nord Stream 1 were reduced during the summer break for repair works. In turn, flows via Ukraine significantly declined since August. Notably, according to an automated data collection by Appygas, for the last three months the daily average gas flow from Russia has been 2,601 GWh/day, less than from Norway which shows 2,937 GWh/day.

Politics: Nord Stream 2, Ukraine

Here, political motivation should not be excluded because of the well-known preferences of Gazprom to prioritise the forthcoming Nord Stream 2 pipeline beneath the Baltic Sea and to decrease transit volumes via Ukraine for well-known political reasons. Gazprom reportedly did not book any additional capacity via Ukraine from October onwards which creates additional psychological pressure on European markets.

Figure 3 indicates that Gazprom has a preference for Nord Stream 1 at the expense of capacity booking via the two transit countries, Belarus and Ukraine. Ironically, EU-based market rules (which are implemented in Ukraine via the Energy Community Treaty) helped Gazprom in putting indirect pressure on the transit country in light of the Nord Stream 2 completion. Some critics warn that with Nord Stream 2 in place, Gazprom will be able to reduce reverse flows from Europe to Ukraine and create conditions for larger Ukrainian energy dependence on Russia.

Meanwhile, most European utilities view the Nord Stream 2 with a positive eye as it will create conditions of secure deliveries to German hubs. Although Nord Stream 2 does not create new market conditions and only redirects the deliveries to fulfill existing long-term contracts, it may actually help in adding more gas to the spot and ease pressure on prices.

Even more, a new signal now comes from Russia, since Moscow plans to permit Rosneft to access the future pipeline. This is a symbolic step towards export demonopolisation which may be positively perceived by the markets.

A risky choice: consumers’ reliance on spot

Historically, a large part of gas supplies in Europe have been indexed to oil, whereas the surplus was traded on hubs, usually on spot. Because of the persistent over-supply observed between 2015 and 2020, the spot price has very often been lower than the oil-indexed price. Instead, the oil-indexed price would offer a more stable ratio since it takes into account the 6-month period for which the oil price average is calculated with a 3-month time lag (Table 1).

To note, some long-term contracts now include a reference to European hubs (mainly TTF and Gaspool) alongside the oil indexation. As a result, in 2020, purely oil-indexed gas flows occupied less than a quarter of the European market. The development of liquid natural gas hubs reinforced by LNG inflows created an opportunity for spot contracts. According to CME Group data, in 2018-2019, up to 35% of new contracts were traded on spot. Other forms of market-based contracts (forward and future contracts) have not gained a similar popularity among European consumers. Then, data collected by Royal Dutch Shell reveals that an overwhelming part of the spot contracts was concluded to add volumes to the existing termed contracts to optimise the price.

Whereas, over the last decade, the spot price has generally been lower than oil-indexed, this summer the spot price bypassed the oil-indexed price by 100-120%! As a result, a large part of utilities found themselves in a trap: no termed contracts in place and a spot price that kept rising to unaffordable levels.

Gas is available, but tied to rising prices

Some utilities anonymously confirmed that their budgets have been limited to purchase necessary gas volumes and therefore they risk a deficit in winter. Consequently, the risks of a gas shortage in winter emerge even despite sufficient levels of gas available in underground storage. In turn, termed contracts with oil price indexation cover about 20% of the gas market volumes – which means that a majority of clients are at risk.

The situation further drives to question earlier decisions by courts who actually required companies to switch to hub-pricing as a ‘normal’ mode of the market practice. Ironically, the oil price is better institutionalised, and should not have been disregarded so much by a large proportion of the gas market players.

Figure 4 also indicates a significant reduction in liquidity change in over-the-counter contracts across Europe. Trading platforms with a larger share of LNG have been mostly affected.

Coal demand resumed

Gas markets cannot be separated from the inter-fuel competition. When gas prices collapsed amid the Covid-19 pandemic in spring 2020, an interesting observation had been conducted by Ole Hvalbye from Rystad Gas Market Cube, who had illustrated how a skyrocketing carbon price and declining gas price stimulated a coal-to-gas shift in the power sector.

However, with the rise of natural gas prices observed since summer 2020 the coal-to-gas switch became less profitable and an adverse effect emerged: coal demand resumed against rising gas price (Figure 5). According to Global Energy Monitor, up to 6 GW of capacity was closed in 2019 and 10GW more in 2020. Meanwhile, commissioning new coal power plants fell by 34% in 2019-20. In Germany alone, up to 5 GW of hard coal and lignite capacity were removed from the market by the end of 2020.

More recently, RBN Energy published a report showing a correlation between record-high gas and carbon prices with a claim that the Emission Trading Scheme design actually drove gas prices up. In turn, carbon-free but intermittent energies do not necessarily ensure system reliability and therefore did not provide the necessary productivity during the crisis.

Four conclusions

The current energy crisis is a combination of a number of market and policy trends that occurred over the last years in Europe. Four conclusions may be drawn from the crisis.

First, the crisis confirms that the European gas market is now more reliant on LNG for competitiveness. Fewer LNG inflows mean less gas for hubs. The unexpected side of the crisis is the price hike that occurred in summer, during the low-demand season. The EU faces a tough competition for LNG supplies and might need to consider a more consistent pro-LNG strategy in energy transition to regain international attractiveness.

Second, the crisis reveals the importance of information flows alongside commodity cycles. Poor information created a false sense of security, leading decision-makers to accept the argument from Gazprom and its European partners of Nord Stream 2 that the new pipeline will ease the market imbalance. Meanwhile, the current crisis increases political pressure on Ukraine engendering new geopolitical challenges for the EU. Yet, we should not exclude that Nord Stream 2 will contribute to a more liquid gas hub in Germany where a merger between Gaspool and NCG creates a new Trading Hub Europe.

Third, the crisis is more about consumers’ over-reliance on spot rather than as a result of a supply shock. In principle, additional volumes can be made available for spot trade by winter, whereas underground storages are sufficient to ensure supplies for long-term contracts. However, many utilities miscalculated both the market trend and the unexpected cost of the spot deals. For some, energy deficits will become a reality towards January-February 2022.

Finally, one may observe that gas demand was first stimulated by an ever-growing carbon price, but then gas price hikes pushed the carbon price instead. Meanwhile, weakened inter-fuel competition and reliance on intermittent energies have only amplified electricity price hikes. Thus, the main challenge in European energy markets is to ensure system reliability to avoid shortages and ensure inter-fuel competition.

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Andrei Belyi is founder and CEO of energy consulting firm Balesene OU, Estonia, and Adjunct Professor of energy law and policy at the University of Eastern Finland