Gas Line is a quarterly publication that looks at major news stories in global gas—ranging from project development to markets and geopolitics. My goal is not to cover every story but to draw connections between stories across time and space in order to shed light on the major themes that will drive global gas markets in the years ahead. My main takeaways from this quarter:
Big Shifts in World LNG Map in 2021
The bottom line: The liquefied natural gas (LNG) market witnessed profound shifts in 2021. China finally emerged as the world’s largest importer, while the United States narrowed the gap with Australia and Qatar and is due to become the world’s largest exporter in 2022. LNG flows into South America spiked, driven by Brazil and Argentina, while Mexico’s imports declined to almost zero. Egypt’s exports reached a 10-year high, while Jordan effectively ceased imports. India’s imported volumes declined, as did Europe’s. All these changes are a reminder that this market remains incredibly dynamic and fluid and that our mental maps of this system need to keep adjusting year after year.
The backstory: The LNG map changed a lot in 2021. On the supply side, Australia finally edged ahead of Qatar, following two years where the two had been effectively tied. Meanwhile, the United States became the world’s third-largest LNG exporter for the year, pulled ahead of Qatar in November, and narrowed the gap with Australia in December. By year’s end, a lot of that U.S. LNG was headed to Europe, triggering a sharp price correction there. And unless something astonishing happens, the United States will become the world’s largest LNG exporter in 2022.
On the demand side, China surpassed Japan to become the world’s largest LNG importer. But that switch came with some costs: the price that China paid for LNG topped $18 per million British thermal units in November 2021, far above what the country paid for pipeline gas. It also came with a growing dependence on Australia and the United States—a fact that strategists in Beijing are unlikely to welcome. Yet that’s the geography of supply and demand now.
Beyond the top of the table, the year witnessed a number of other interesting changes. On the import side of the ledger, Mexico and Jordan effectively disappeared as LNG markets, turning instead to pipeline imports to meet their needs. India’s LNG imports fell for the first time since 2013, evidence, perhaps, of that country’s price sensitivity. Brazil’s imports boomed, courtesy of a drought that pushed up demand for gas-fired power: the country imported almost as much in 2020 as it did the previous three years combined. Argentina’s LNG imports rose to the highest point since 2017, although they remained at nearly half the level of the peak (in 2013).
On the supply side, Egypt returned as a major player, exporting almost 7 million tons of LNG, the highest in a decade. Its exports went mostly to Asia, especially China, India, and Pakistan. But Turkey was the second-largest recipient of Egyptian LNG, an ironic twist given the constant complaints from Turkey that it is being shut out of the gas game in the eastern Mediterranean. Other countries faced serious supply troubles: LNG exports fell 90 percent in Norway, 35 percent in Peru, 32 percent in Trinidad, and 18 percent in Nigeria. Combined, those losses amounted to 11 million tons—enough to satisfy the import needs of a country like the United Kingdom.
European Gas Prices Went Berserk
The bottom line: Gas prices in Europe reached unprecedented levels in Q4 2021. These prices raise profound questions about how the gas market operates in Europe, about the role and responsibilities of supplier companies like Gazprom, and about the need to provide a better structure for managing the big swing in gas demand between summer and winter. Europe needs a new effort to strengthen the institutions meant to provide gas security, and it cannot let the imperative of the energy transition act as an excuse to delay this work.
The backstory: Gas prices in Europe and the spot price for LNG in Asia were elevated for much of 2021, but they reached unprecedented heights in Q4. Before 2021, the high point at the Title Transfer Facility (TTF) in the Netherlands was €35 per megawatt hour (MWh). Between August and December 2021, the closing price was above €35/MWh every day. For a brief moment, on December 21, prices topped €181/MWh. In other words, the high point in 2021 was five times higher than the historical peak. And while Europe’s gas crisis had spillover effects into electricity and the Asian spot LNG price, no other major energy commodity experienced a similar rally.
These prices raise major questions about the functioning of the European gas market (and the spot market for LNG). The fundamentals did not justify such prices. The market was tight, of course, but not that tight. What drove prices up was a fear that Europe might run out of gas in February or March. It was anxiety, not an actual shortage, that drove prices so high. That’s why a modest amount of LNG going into Europe in December and January crashed prices. Could such a vicious cycle be tempered, especially since high prices did little to attract gas supplies (who wants to buy gas at the top and be left holding excess supply when prices crash)? This is a serious question for policymakers to grapple with.
Russia’s role in this crisis also deserves further scrutiny. At a minimum, it seems like Gazprom’s failure to fill its storage facilities in Europe was a major driver of the perceived inadequacy of European reserves for the winter. Do companies have any obligations to use the storage capacity they have reserved, and could that capacity have been released to other parties? Should Europe impose the same responsibilities to external suppliers like Gazprom as it does to importers? Could this be a new avenue through which Gazprom exercises market power, even if its behavior in 2021 might be better explained by the need to refill storage in Russia after the cold winter of 2021? All these are important questions for Europe to consider.
More broadly, these prices exposed a deeper problem for Europe: seasonal balancing. In the past, Europe has relied on a mix of domestic production, storage, and pipeline imports to meet the huge seasonal swing in gas demand. With gas production declining, the continent is far more reliant on storage and imports, including LNG. This is a problem. LNG is not very seasonal because it makes sense to produce at capacity year-round, and Asia absorbs the market’s seasonal capacity.
This leaves Europe in a bind. In 2021, South America imported a lot of LNG during the (Northern Hemisphere) summer, which left less LNG for Europe to import to refill storage. In fact, Europe was able to secure additional LNG in December once the needs of South America subsided. But Europe needs a more permanent fix to this problem. No matter how quickly the energy transition takes place, this seasonal challenge will persist. Europe needs better solutions.
Nikos Tsafos is the James R. Schlesinger Chair for Energy and Geopolitics with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.
Commentary is produced by the Center for Strategic and International Studies (CSIS), a private, tax-exempt institution focusing on international public policy issues. Its research is nonpartisan and nonproprietary. CSIS does not take specific policy positions. Accordingly, all views, positions, and conclusions expressed in this publication should be understood to be solely those of the author(s).
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