European market’s paradoxes. Why is gas more expensive in summer than in winter?

September 29, 2021

Published in corporate Gazprom Magazine Issue 9, written by Sergey Komlev, Gazprom Export

The fact that growing demand for natural gas in the periods of limited supply tends to push the price up requires no explanation. There is a need for some explanations, however, with regard to the unparalleled dynamics of gas prices both in terms of their range and growth duration, as well as the lack of expected adjustments of summer prices against winter ones. Not only have the latter not been revised downward, as they usually are during low seasonal demand, but they have also exceeded the winter maximums. This article offers some explanations for these developments.

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Unpredictability due to weather factor

The ability to surprise demonstrated by gas markets, especially the European one, is not so much unexpected as it is problematic. How can one make well-reasoned investment decisions when the market trends reverse themselves in the course of 12 to 18 months? For instance, in the period from January 2019 through May 2020 the quotations of day-ahead contracts in Europe suddenly dropped 8-fold, only to skyrocket 22-fold in September 2021 just as unexpectedly. This price volatility limits the possibilities of precisely estimating the cash flow for the payback period of long-term loans required for infrastructure projects. Why are gas prices so unpredictable?

Forecasting prices for natural gas is as difficult as forecasting the weather. This should be understood literally. The utilities sector, where consumption directly depends on weather conditions, accounted for 43 per cent of the European gas market in the first half of 2021. If humanity learned to forecast weather months ahead with perfect certainty, it would become possible to make precise forecasts for the length of the heating period and the number of days where air conditioning would be needed, producing reliable estimates of weather-dependent gas demand for the utilities sector. However, at the current juncture weather forecasts become highly unreliable several days ahead of time.

Gas consumption in power generation, which at 29 per cent is the second-largest market sector after the utilities sector, is indirectly influenced by the weather factor in terms of power generated from renewables. Can one precisely forecast wind strength, the number of sunny days or the levels of water in reservoirs at least a few months ahead? The answer is clear. In terms of the weather factor, the gas industry is akin to agriculture, except in agriculture the weather affects the supply while in the gas industry it affects the volumes of gas consumption.

The powerful and unpredictable weather factor was exclusively playing in favor of natural gas buyers in 2020, while in 2021 the situation reversed itself. The weather “responded” to the needs of the sellers.

To wit, the weather index in Europe through the first half of 2021 was generally above the climate normal and last year’s level (102.9 per cent against 90.1 per cent in the first half of 2020). In Q1 2020, this index was at a minimum and only approached the average indicators of 2010–2020 in Q2 2020. The weather index was close to the norm in Q1 2021, but in Q2 it was already well above it, setting a new maximum in April and May (see Fig. 1).

Fig. 1. Weather index in Europe^*

^* The weather index is calculated as the sum of degree days for the respective month: HDD (Heating Degree Days) and CDD (Cooling Degree Days). The calculations took into account weather data from more than 90 regions of various European countries.

Source: Gazprom Export

Actual gas consumption grew by almost 39 billion cubic meters to 316 billion cubic meters in the first half of 2021. The weather factor accounted for 6.3 billion cubic meters of this amount. In the first half of 2020, the negative influence of this factor caused gas demand to decline by 15.9 billion cubic meters. Therefore, the weather factor has had a dominant impact year on year (+22.2 billion cubic meters).

Recovery of European economy

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Despite the ongoing pandemic, economic recovery in European countries was on the upswing in the first half of 2021. Europe’s industrial production index climbed by 15.1 per cent in six months, while in the same period of 2020 it had dropped by 13 per cent.

This economic recovery is evident in the growing demand for electric power. In the first half of 2021, power generation in Europe’s five largest countries rose by 4.5 per cent against the first half of 2020. The workload of gas-fired power plants grew to 43 per cent versus 36 per cent a year earlier.

The power generation sector, just like the utilities sector, took the lead in consumption growth in the first half of 2021, which was also facilitated by reductions in wind and hydropower generation across Europe (see Table 1).

Table 1. Breakdown of gas consumption in non-FSU European countries by sectors, billion cubic meters (bcm)

Source: Gazprom Export

Supply of natural gas

Against the background of favorable weather and economic recovery, gas demand broke another monthly record (in April) in the first half of 2021. The overall amount of gas consumed in the entire period is second-highest since the all-time high recorded in the first half of 2010.

The heightened demand for natural gas was satisfied via expanding imports (+20.8 billion cubic meters, or +12.8 per cent), as well as increasing net withdrawal from UGS facilities, which exceeded last year’s level by 16.6 billion cubic meters. This substantially affected the level of reserves. At the same time, gas production in Europe saw its largest decline in absolute terms since the first half of 2014 (–11.1 billion cubic meters, or –9.8 per cent).

The share of LNG decreased significantly in the structure of imports in January–June 2021, falling from 41.5 per cent for six months of 2020 to 31.0 per cent for the first half of 2021. This was caused by the rerouting of LNG flows from Europe to Asia-Pacific and Latin America. LNG supplies in absolute terms dropped by 10.74 billion cubic meters, or 15.9 per cent.

The process of LNG “leaking” from Europe was an uneven one. In January 2021, LNG supplies were well below the level observed in 2020 and even below the average level for 2015–2020. Nevertheless, Q1 2021 saw LNG supplies recover and go back to last year’s levels as early as in March. In Q2, however, LNG imports to the European market started another steady decline due to increased demand for gas in Asia-Pacific caused by hot weather and renewed economic growth. The Chinese economy was the main driver of gas demand.

The capacity use rate for liquefaction facilities in the United States, which fell to 29 per cent in Q3 2020, skyrocketed to 100 per cent by the end of Q4 2020 and remained high in Q1 2021. Owing to hot weather in Asia and Latin America coupled with a rapid rise in gas prices at key LNG markets, the capacity use of liquefaction facilities exceeded 80 per cent throughout Q2 of this year.

Imports of pipeline gas, on the other hand, grew by 31.5 billion cubic meters, or 33.1 per cent (see Tables 2, 3, 4). Offtake of Russian pipeline gas went up by 17.2 billion cubic meters, or 22.1 per cent, while the amount of LNG exports from Russia remained roughly the same. Gazprom’s pipeline gas supplies were marked by all-time records, with the major buyers accounting for the bulk of new growth (see Fig. 2, 3). According to preliminary data, the Company’s output by late July reached 298.2 billion cubic meters of gas, which is an increase of 18.4 per cent against the same period of last year. Meanwhile, its gas exports added 23.2 per cent, and supplies to non-FSU countries went up to 115.3 billion cubic meters. These data prove the absurdity of the accusations about insufficient supplies leveled against Gazprom.

Fig. 2. Gazprom’s supplies to non-FSU European countries, bcm

Source: Gazprom Export

Fig. 3. Gazprom’s supplies to major buyers in non-FSU European countries, bcm

Source: Gazprom Export

Pipeline gas supplies were ramped up by Algeria (+12.2 billion cubic meters) due to, among other things, low oil-linked prices. Meanwhile, LNG deliveries from Algeria grew at a smaller rate (+1.55 billion cubic meters).

Limited supply of LNG and the onset of winter in Asia-Pacific caused average spot prices in Asia to spike to USD 9.5 per 1 million BTU in the first half of this year (compared to USD 3.8 in the same period of 2020). As a result, the first half of 2021 saw the “Asian premium” grow on average to USD 2.6 per 1 million BTU versus USD 0.8 in Q1–2 of last year. In Q2 2021, the level of the “Asian premium” hovered around zero against Europe’s growing gas demand. The dependence of price dynamics at global markets on the reallocation of LNG flows between Europe and Asia serves as yet another proof of the fact that the destabilization of these markets is caused mainly by flexible supplies of LNG. Flexible LNG includes gas purchased by aggregators and LNG purchased by end consumers, who have the right to reroute LNG to destinations with the highest prices.

Europe’s expectations for stable LNG supplies from the US are not coming true for a second year in a row. Last year, these supplies were unprofitable due to the low price in Europe. This year, the price was already sufficient to cover the supply costs, but it was still less attractive than the one offered by Asia. Notably, LNG supplies from the US reached a record-high level in the first half of 2021 (+13.1 billion cubic meters, or +38.3 per cent), albeit thanks to China, Japan, and Brazil. At the same time, a significant decrease in supplies was observed in European countries such as Belgium, Italy, Spain, and Turkey (see Table 5).

Table 2. Supplies by Europe’s largest gas exporters, bcm

^* Yamal LNG and Cryogas-Vysotsk projects.

Source: Gazprom Export

Table 3. Supplies by Europe’s largest producers, bcm

^* Figures for Norway are for the pipeline gas and LNG supplied to the European market and do not include LNG supplies to Asia and the Americas.

Source: Gazprom Export

Table 4. LNG imports to European market, bcm

^* Yamal LNG and Cryogas-Vysotsk projects.

Source: Gazprom Export

Table 5. LNG supplies from USA broken down by countries, bcm

Source: Gazprom Export

Why are spot prices so volatile?

While the emergence of the seller’s market in Europe can be explained by the shortage in LNG supplies and decline in indigenous production, along with Norway’s inability to ramp up its supplies, it has to be noted that the current volatility of spot prices seems clearly exaggerated. For instance, this September, the day-ahead contract price per 1,000 cubic meters was about USD 200 higher as compared to daily quotations under a year-ahead contract. Usually, this phenomenon is attributed to the activities of profiteers. However, no matter how convenient this explanation may be, it does not uncover the mechanism behind hyper volatility.

Another popular notion is that gas market participants are overly emotional and thus prone to exaggerating the risks of that market. This psychology-based explanation seems unconvincing. It is hard to imagine market participants who are more rational in their reasoning than traders are.

This volatility in short-term forward contracts stems from the unique architecture of the gas market, and namely, in our opinion, its two-segment structure. Regional export markets of natural gas in Europe and Southeast Asia have a two-segment structure, and thus include two unequal parts. One segment, the larger one, uses long-term supply contracts, while the other one uses spot supplies. In 2021, the share of spot supplies in the European market is about 30 per cent.

The segment of long-term contracts is a well-balanced one by definition, as the nominations for supply volumes are coming from the buyers, who order exactly as much gas as they need. Accordingly, all imbalances existing in the regional (national) market are concentrated in the small segment of spot supplies, and that is why its prices show an excessive response even to minor (from the point of view of the entire market) deviations of demand from supply. This point can be exemplified as follows.

In our opinion, the extent of gas shortage in the European market can be judged from the difference between the current level of reserves in Europe’s UGS facilities and their average level registered in 2015–2020. Since early 2021, the negative difference in the level of reserves has been not decreasing but growing from 2.6 billion cubic meters in January to 14 billion cubic meters in June and has remained at the same level in September.

In the first half of 2021, the amount of consumption in the European gas market stood at 316 billion cubic meters. In the context of European consumption in general, the shortage in the gas market is relatively small: 4 per cent. However, compared to the size of the spot segment, which is 95 billion cubic meters (30 per cent of 316 billion cubic meters), 14 billion cubic meters makes a much more considerable portion: 14 per cent. It is not surprising, then, that the prices in the spot segment of demand show a bigger decline in response to such imbalance than they would in a hypothetical situation when, in the absence of long-term contracts, the equilibrium price would reflect the demand¬–supply ratio for the entire market. This explains the multiplier effect that the imbalances between demand and supply have on the prices in the spot segment.

Photos provided by PGNiG SA, Qatargas