2020 was an unprecedented year for liquefied natural gas (LNG). The COVID-19 pandemic impacted most major markets, with initial operational challenges at some regasification terminals and strict lockdowns initially affecting demand. Countries better able to contain the spread of the coronavirus saw a quicker recovery and, in some cases, strong year-over-year growth in demand. LNG spot prices fell to their lowest-ever levels in the summer but then increased rapidly toward the end of the year, with winter 2020–21 spot prices achieving record highs. Overall, the volatility in pricing and demand resulted in significant drops and swings in liquefaction-plant utilizations through much of the year.
McKinsey has developed two advanced analytics solutions to help monitor gas markets in real time. First, LNGFlow tracks global LNG fleet utilization and daily movements and monitors trade flows and supply and demand. Second, EUPipeFlow tracks daily natural gas flows in the EU pipeline system, providing analyses of supply, demand, and storage levels, enabling users to compare utilizations of key infrastructure points.
After analyzing the data gathered by these solutions, we identified key insights from the past year that help explain the implications for LNG markets in 2021 and beyond.
Global LNG volumes
Despite COVID-19, global LNG volumes delivered in 2020 still grew, albeit by just 2.5 million tons (MT) (+1 percent) to 358.9 MT, as compared with the 356.4 MT delivered in 2019 (Exhibit 1). Demand increases came from China and India, together importing close to an additional 10 MT (Exhibit 2). Other importing regions experienced net decreases in LNG imports of approximately 7 MT in response to either demand destruction or higher prices later in the year.
COVID-19 also caused an unprecedented level of disruption to supply as global gas prices dropped to record lows. Some suppliers decreased supply in response to low spot prices or operational challenges. Through the summer, many buyers and traders decided to cancel supplies from the United States, as they could no longer be sold for a profit into either Asian or European spot markets. Nevertheless, despite the cargo cancellations, the United States was able to increase production year over year as new liquefaction facilities (such as Cameron and Freeport) continued ramping up into 2020.
Pricing
The average spot price for LNG in Japan was $4.5/MMBtu,1 down 31 percent from the $6.5/MMBtu in 2019 (Exhibit 3). As a result of the economic slowdown and disruptions caused by COVID-19, LNG prices dropped to record lows, with some cargoes in Asia understood to have been sold at prices below $2/MMBtu over the summer. However, prices began to strengthen by the fourth quarter, with spot rising to levels comparable with typical oil-linked contracts2 and eventually closing around $7/MMBtu for December deliveries. Spot prices continued to rally into the new year, eventually reaching a record high in early 2021, with some cargoes reported to have sold for close to $40/MMBtu.
There were several key drivers behind the unprecedented recovery in price. First, harsh winter conditions and record low temperatures across North East Asia led to increased power demand throughout the region, as demonstrated by Beijing experiencing its coldest December day in 42 years on December 29. Meanwhile, high snowfall reduced solar generation, resulting in increased spot demand for LNG. Second, projects such as Snøhvit in Norway reported operational difficulties, which constrained supply. And third, the increase in winter demand and low availability of vessels caused LNG carrier spot-charter rates to increase sharply to nearly $150,000 per day in December, up from the low-$30,000 per day rates exhibited in the summer. Charter rates in 2020 averaged approximately $65,000 per day, down 11 percent from 2019.
Demand
Global LNG imports in 2020 increased 2.5 MT (+1 percent) to 358.9 MT. The first quarter saw imports increase significantly, with 9.3 MT of additional supply making its way to markets. However, after the spread of COVID-19 resulted in nationwide lockdowns and a global economic slowdown, imports began to decrease year over year starting in the second quarter, resulting in a 6.8 MT decrease in imports through the end of 2020 (Exhibit 4).
Demand in mainland China grew 6.4 MT (+10 percent) to 67.8 MT, experiencing a slight decrease in imports in the first quarter—particularly in January and February—as it was the first country to implement pandemic-induced lockdowns. However, China then experienced significant growth from the second quarter onward as the economy continued to grow after successfully containing the outbreak of COVID-19.
Demand in JKT3 was largely unchanged, falling 0.2 MT to 133.4 MT, as the fall in Japanese imports (–1.7 MT) was largely offset by increased imports by Taiwan (+1.4 MT). As one of the countries considered to have best contained the spread of COVID-19, Taiwan’s energy demand remained robust in 2020.
Indian demand grew 3.1 MT (+13 percent) to 27.0 MT. This is likely a result of buyers purchasing distressed cargoes in early 2020 in anticipation of robust natural-gas demand. In addition, imports in the second quarter saw a drop as nationwide lockdowns were implemented to contain the spread of COVID-19. Third- and fourth-quarter imports returned to positive territory after lockdown measures were lifted.
Including re-exports, European LNG demand fell 4.1 MT (–5 percent) to 82.4 MT, driven by significant import decreases by France (–2.6 MT), Belgium (–1.9 MT), and Italy (–0.8 MT). Meanwhile, Turkish LNG demand grew 1.6 MT. An overall increase in first-half imports was driven by an additional 7.4 MT of US LNG making its way to Europe.
Finally, the rest of the world saw LNG imports decrease by a total of 2.7 MT (–6 percent) to 48.3 MT, with the largest decreases coming from Mexico (–2.8 MT), Indonesia (–1.3 MT), Pakistan (–0.7 MT), and the Dominican Republic (–0.6 MT), and with increases coming from Bangladesh (+0.8 MT), Kuwait (+0.6 MT) and Thailand (+0.6 MT).
EU gas-demand deep dive
Gas demand in the European Union declined by 1.6 percent in 2020 (–7 bcm4) (Exhibit 5). Russian-piped supplies saw a significant decline, decreasing some 25 percent—or 44 bcm—versus 2019. A few factors are responsible for this decline, including warm early months in 2020, some remaining oil-indexed contracts being displaced by LNG, and reductions in industrial demand. European production declined 8 bcm, while pipeline exports to Turkey, Switzerland, and other non-EU markets were reduced by 17 bcm. There was also substantial change in the European storage position. Whereas 2019 saw 20 bcm of net injections, 2020 saw 13 bcm of net withdrawals—a 33 bcm swing.
Supply
Global LNG exports in 2020 increased 2.6 MT (+1 percent) to 370.7 MT. The first quarter saw exports increase significantly, with 9.6 MT of additional supply entering the market. However, the effects of COVID-19 severely impacted supply in the second and third quarters, as low demand and gas prices resulted in mass cancellations of US-sourced cargoes and decreased utilizations at liquefaction facilities (Exhibit 6). As prices began to recover in the fourth quarter, exports from the United States began to rise again but were offset by a steep decline in supply from other producing regions.
The top four producers (Australia, Qatar, Russia, and the United States) increased their combined share of total global exports to 65 percent, as exports increased 14.8 MT (+7 percent) to 241.3 MT in 2020. The United States alone added 12.3 MT, which was primarily driven by the ramp-up of new projects and partially offset by the decline in exports from Sabine Pass LNG. Other producers saw exports drop 12.2 MT (–9 percent) to 129.4 MT in 2020. The countries with the largest drops were Trinidad and Tobago (–2.5 MT), Egypt (–2.2 MT), Algeria (–1.8 MT), Norway (–1.8 MT), Malaysia (–1.8 MT), and Indonesia (–1.4 MT).
The changes to LNG supply in 2020 can be categorized into five buckets (Exhibit 7).
US LNG ramp-up. The ramp-up of LNG projects in Freeport, Cameron, Corpus Christi, Cove Point, and Elba Island added a combined 16.6 MT in 2020, with the total exports from these projects reaching 30.8 MT—up 117 percent from 2019.
Increased utilization. Increased utilization and ramp-up of other projects globally, such as in Russia and Australia, added 7.0 MT to exports in 2020. Ichthys LNG continued its ramp-up and added 1.0 MT to exports in 2020, whereas Pluto LNG increased exports by 0.8 MT following the completion of its extended maintenance in 2019.
Decreased utilization. Lower utilization rates at liquefaction facilities resulted in global exports falling by 10.0 MT. In the United States, Sabine Pass LNG saw exports fall 4.3 MT as low gas spot prices in Asia and Europe made it uneconomic to deliver US LNG to these markets. Other producers, such as Malaysia LNG, also decreased exports by 1.8 MT, reportedly to reduce portfolio exposure to low LNG spot prices. Malaysia LNG was particularly exposed to the spot market after many of its long-term sales and purchase agreements (SPAs) expired in recent years, including the contract with JERA for delivery of up to 4.8 MTPA,5 which concluded in 2018.
Gas-supply decline. Upstream gas-supply declines and issues removed an additional 5.3 MT from the market as older producers, such as Badak LNG, Atlantic LNG, and EG LNG, each of which has been producing LNG for more than 30 years, saw exports drop by 31 percent, 19 percent and 14 percent, respectively.
Operational issues. Operational issues saw exports fall further by 5.7 MT in 2020. Turbine issues caused exports from Snøhvit LNG to drop 1.8 MT (–38 percent), welding issues saw exports from Gorgon LNG drop 1.4 MT (–10 percent), and a halt in production at Prelude FLNG saw exports drop 0.8 MT (–87 percent).
US LNG-supply deep dive
US LNG exports increased to 49.6 MT in 2020, a rise of 12.3 MT (+33 percent). The increase was driven by the ramp-up of LNG projects such as Freeport (+7.6 MT), Cameron (+6.5 MT), Corpus Christi (+1.7 MT), Elba Island (+0.7 MT), and Cove Point (+0.2 MT), which together added 16.6 MT of supply. Sabine Pass saw exports drop 4.3 MT (–18 percent) to 18.9 MT as low gas prices resulted in flexible US LNG cargoes being cancelled (Exhibit 8). More than 175 US LNG cargoes for loading between April and November are reported to have been cancelled in 2020.
A total of 46.4 MT of US LNG was delivered in 2020. Europe accounted for 40 percent of volumes delivered but with a significant ramp down in the summer as prices fell below cash-cost break-evens (Exhibit 9). Furthermore, some 19.9 MT went to Asian markets. These deliveries were particularly strong in November and December 2020 with 5.5 MT supplied, compared with the 3.2 MT during the same period in 2019. This was driven by strong winter demand and high energy prices in Asia, creating heating demand for spot LNG. Last, the lifting of Chinese tariffs on US LNG in April 2020 led to the resumption of imports after a year of interruption, reaching nearly one MT by December.
Based on prevailing gas prices and charter rates, the average short-run marginal profit per cargo6 of US LNG sold and delivered into the Asian spot market crossed into negative territory for the first time in 2020, leading to significant cargo cancellations (Exhibit 10). That said, given that the tolling fees paid by buyers—regardless of whether the cargoes are taken or cancelled—typically exceed $10 million per cargo, buyers of US LNG experienced substantial losses in 2020. With the high spot LNG prices of early 2021, however, it is estimated that the profits for some US LNG delivered in Asia over the 2020–21 winter can exceed $80 million per cargo for sellers who secured sales at the peak of the market and have access to cost competitive shipping capacity, enough to cover for tolling fees and capture excess profits.
Re-exports
Re-exports and transshipments, such as from Yamal LNG, increased by 3.3 MT (+69 percent) to 8.1 MT. The largest increases in re-exports and transshipments came from Belgium, which saw a 2.6 MT (+206 percent) increase to 3.9 MT (Exhibit 11). Re-exports and transshipments from the Netherlands dropped 0.2 MT (–27 percent) to 0.4 MT, and re-exports from France were largely unchanged at 2.1 MT. Singapore saw a 0.8 MT (+188 percent) increase in re-exports to 1.2 MT.
European re-exports and transshipments totaled 6.4 MT in 2020, of which 3.3 MT (51 percent) were delivered to Asia, 2.3 MT (36 percent) to Europe, and 13 percent to other buyers in the Middle East and the Americas. China imported a total of 1.7 MT of European re-exports, approximately half of which was delivered in the fourth quarter, as China continued to show strong demand growth following the containment of the coronavirus.
Implications for 2021
Despite 2020 being a year of unpredictable challenges for LNG suppliers and buyers, the fourth quarter showed signs of recovery as supply and demand fundamentals began to improve, with the market tightening and LNG prices starting to recover into the winter. These trends are expected to continue into 2021.
Higher gas prices with increased volatility. The price volatility seen in late-2020 may also be a feature of 2021. This will be a consequence of a more balanced supply-and-demand outlook, combined with less gas in storage, leaving key markets such as Europe in a worse position to mitigate market shocks. LNG prices are expected to average higher in 2021 as strong winter demand and the gradual return of economic activity support higher spot LNG prices, as well as increasing oil prices flowing through to prices for oil-linked term contracts. At these prices, US LNG delivered into Asia should yield positive cash-cost margins (that is, excluding tolling fees), meaning US cargoes should see fewer cancellations in 2021. However, the recent rally in US natural gas prices driven by the unprecedented winter storms may add to the list of many factors that could further increase the level of price volatility in 2021.
Demand uncertainty. Higher LNG prices may reduce the pace of demand growth from price-sensitive markets. However, the extent of overall market tightening will be strongly impacted by the pace of Chinese LNG demand growth. With LNG still likely to be more competitive than Central Asian pipeline imports, and with the Power of Siberia pipeline from Russia ramping up slowly, LNG demand should build on the 10 percent growth seen in 2020.
Increased overall liquefaction utilization but limited new LNG. With higher gas prices expected in 2021, suppliers that had reduced utilization to minimize exposure to low spot prices may increase liquefaction utilization and production and return to levels exhibited prior to COVID-19. However, others may continue to struggle with operational and feedgas challenges. With the expected improved margins for US LNG sales into Asia in 2021, a large majority of the 175 US LNG cargoes that were cancelled in 2020 can be expected to make a return into the market; this alone can add more than ten MT to supply in 2021. In addition, ramp-up from new facilities, including Corpus Christi LNG Train 3 in the United States and Yamal LNG Train 4 in Russia, are expected to increase supply by an estimated additional 4 MT.
Changes in LNG purchasing patterns. As buyers recover from the challenges caused by the high spot prices of the 2020–21 winter season and prepare for likely higher average gas prices in 2021, buyers may begin to reconsider their LNG-procurement strategies. This may include the purchase of more short-term strips of cargoes indexed to oil prices rather than remaining overly exposed to the spot market and managing storage inventories at relatively higher levels.
The authors would like to thank Mateusz Czajkowski and Konrad Boszczyk for their contributions to this blog post.
1 Million British thermal units.
2 LNG sold under term contracts has typically been priced at a percentage indexation to oil prices, usually with a lag. The majority of LNG is currently sold under long-term oil-linked contracts.
3 Japan, Korea, and Taiwan.
4 Billion cubic meters.
5 Million tons per annum.
6 Calculated as LNG spot price minus the estimated shipping cost from the United States to North East Asia minus 115 percent times Henry Hub price times the delivered volume.